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ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 80 

[EPA-HQ-OAR-2010-0133; FRL-XXXX-X] 

RIN 2060-AO81 

Regulation of Fuels and Fuel Additives: 2011 Renewable Fuel Standards 

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Notice of Proposed Rulemaking. 

SUMMARY: Under the Clean Air Act Section 211(o), as amended by the Energy 

Independence and Security Act of 2007 (EISA), the Environmental Protection Agency is 

required to set the renewable fuel standards each November for the following year based 

on gasoline and diesel projections from EIA. Additionally, EPA is required to set the 

cellulosic biofuel standard each year based on the volume projected to be available 

during the following year, using EIA projections and assessments of production 

capability from industry. This regulatory action proposes these annual standards for 

cellulosic biofuel, biomass-based diesel, advanced biofuel, and renewable fuels that apply 

to all gasoline and diesel produced or imported in year 2011. This action also presents 

two proposed changes to the RFS2 regulations. The first would create a temporary and 

limited means for certain renewable fuel producers to generate delayed RINs after they 

have produced and sold renewable fuel. This proposed provision would apply only to 

those producers who use canola oil, grain sorghum, pulpwood, or palm oil to produce 

renewable fuel. The second proposed regulatory provision would establish criteria for 

foreign countries to adopt an aggregate approach to compliance with the renewable 

biomass provision akin to that applicable to the U.S. 

DATES: Comments must be received on or before [insert date 30 days after 

publication in the federal register]. 

Hearing: We do not expect to hold a public hearing. However, if we receive such a 

request we will publish information related to the timing and location of the hearing and 

the timing of a new deadline for public comments. 

ADDRESSES: Submit your comments, identified by 

Docket ID No. EPA-HQ-OAR-2010-0133, by one of the following methods: 

• www.regulations.gov: Follow the on-line instructions for submitting comments.

• Email: asdinfo@epa.gov. 

• Mail: Air and Radiation Docket and Information Center, Environmental 

Protection Agency, Mailcode: 2822T, 1200 Pennsylvania Ave., NW., Washington, DC 

20460. 
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• Hand Delivery: EPA Docket Center, EPA West Building, Room 3334, 1301 

Constitution Ave., NW., Washington, DC 20460. 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-2010-0133. 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 e-mail. The www.regulations.gov website 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 e-mail 

comment directly to EPA without going through www.regulations.gov your e-mail 

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. For additional instructions on submitting 

comments, go to Section I.B of the SUPPLEMENTARY INFORMATION section of 

this document. 

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: Julia MacAllister, Office of 

Transportation and Air Quality, Assessment and Standards Division, Environmental 

Protection Agency, 2000 Traverwood Drive, Ann Arbor MI 48105; Telephone number: 

734-214-4131; Fax number: 734-214-4816; E-mail address: macallister.julia@epa.gov, 

or Assessment and Standards Division Hotline; telephone number (734) 214-4636; Email address asdinfo@epa.gov. 

SUPPLEMENTARY INFORMATION: 

I. General Information 
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A. Does this Action Apply to Me? 

Entities potentially affected by this proposed rule 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. Potentially regulated categories 

include: 

Category NAICS1

Codes 

SIC2

Codes 

Examples of Potentially Regulated Entities 

Industry 

Industry 

Industry 

Industry 

Industry 

Industry 

 

Industry 

324110 

325193 

325199 

424690 

424710 

424720 

454319 

2911 

2869 

2869 

5169 

5171 

5172 

5989 

Petroleum Refineries 

Ethyl alcohol manufacturing 

Other basic organic chemical manufacturing 

Chemical and allied products merchant wholesalers 

Petroleum bulk stations and terminals 

Petroleum and petroleum products merchant 

wholesalers 

Other fuel dealers 

1

 North American Industry Classification System (NAICS) 

2

 Standard Industrial Classification (SIC) system code. 

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

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

of entities that EPA is now aware could potentially be regulated by this proposed action. 

Other types of entities not listed in the table could also be regulated. To determine 

whether your activities would be regulated by this proposed action, you should carefully 

examine the applicability criteria in 40 CFR part 80. If you have any questions regarding 

the applicability of this proposed action to a particular entity, consult the person listed in 

the preceding section. 

B. What Should I Consider as I Prepare My Comments for EPA? 

1. Submitting CBI 

Do not submit this information to EPA through www.regulations.gov or e-mail. 

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. 

2. Tips for Preparing Your Comments 
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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. 

Outline of this preamble 

I. Executive Summary ................................................................................................... 6

A. Statutory Requirements for Cellulosic Biofuel .............................................................. 7

B. Assessment of 2011 Cellulosic Biofuel Volume .............................................................. 8

C. Advanced Biofuel and Total Renewable Fuel .............................................................. 10

D. Proposed Percentage Standards.................................................................................... 10

II. Volume Production and Import Potential for 2011............................................ 13

A. Cellulosic Biofuel ............................................................................................................ 13

1. Domestic Cellulosic Ethanol......................................................................................................14

2. Domestic Cellulosic Diesel ........................................................................................................16

3. Other Domestic Cellulosic Biofuels...........................................................................................17

4. Imports of Cellulosic Biofuel.....................................................................................................17

5. Summary of Volume Projections...............................................................................................18

B. Potential Limitations ...................................................................................................... 21

C. Advanced Biofuel and Total Renewable Fuel .............................................................. 21

D. Biomass-Based Diesel ..................................................................................................... 24

III. Proposed Percentage Standards for 2011 .......................................................... 27

A. Background ..................................................................................................................... 27

B. Calculation of Standards................................................................................................ 27

1. How Are the Standards Calculated?...........................................................................................27

2. Small Refineries and Small Refiners..........................................................................................31

IV. Cellulosic Biofuel Technology Assessment......................................................... 32

A. What Pathways are Valid for the Production of Cellulosic Biofuel?......................... 32
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B. Cellulosic Feedstocks...................................................................................................... 34

C. Emerging Technologies .................................................................................................. 34

1. Biochemical ...............................................................................................................................36

a. Feedstock Handling...............................................................................................................37

b. Biomass Pretreatment............................................................................................................38

c. Hydrolysis .............................................................................................................................38

i. Acid Hydrolysis.................................................................................................................39

ii. Enzymatic Hydrolysis .......................................................................................................39

d. Fuel Production .....................................................................................................................40

e. Fuel Separation......................................................................................................................41

f. Process Variations .................................................................................................................42

g. Current Status of Biochemical Conversion Technology .......................................................42

h. Major Hurdles to Commercialization ....................................................................................43

2. Thermochemical.........................................................................................................................43

a. Ethanol based on a Thermochemical Platform......................................................................47

b. Diesel and Naphtha Production based on a Thermochemical Platform.................................48

3. Hybrid Thermochemical/Biochemical Processes.......................................................................49

4. Pyrolysis and Depolymerization ................................................................................................51

a. Pyrolysis Diesel Fuel and Gasoline.......................................................................................51

b. Catalytic Depolymerization...................................................................................................53

5. Catalytic Reforming of Sugars to Gasoline................................................................................54

V. Proposed Changes to RFS2 Regulations ................................................................ 56

A. Delayed RIN Generation for New Pathways................................................................ 56

B. Criteria and Process for Adoption of Aggregate Approach to Renewable Biomass 

for Foreign Countries.............................................................................................................. 58

1. Criterion and Considerations......................................................................................................59

2. Data Sources ..............................................................................................................................60

3. Petition Submission....................................................................................................................61

4. Petition Process..........................................................................................................................62

VI. Public Participation ............................................................................................. 64

A. How Do I Submit Comments?....................................................................................... 64

B. How Should I Submit CBI to the Agency?................................................................... 64

VII. Statutory and Executive Order Reviews.............................................................. 66

A. Executive Order 12866: Regulatory Planning and Review......................................... 66

B. Paperwork Reduction Act.............................................................................................. 66

C. Regulatory Flexibility Act.............................................................................................. 66

D. Unfunded Mandates Reform Act .................................................................................. 67

E. Executive Order 13132: Federalism.............................................................................. 67

F. Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments............................................................................................................................ 68

G. Executive Order 13045: Protection of Children from Environmental Health Risks 

and Safety Risks....................................................................................................................... 68

H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect 

Energy Supply, Distribution, or Use...................................................................................... 68
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I. National Technology Transfer Advancement Act ....................................................... 68

J. Executive Order 12898: Federal Actions to Address Environmental Justice in 

Minority Populations and Low-Income Populations ........................................................... 69

VIII. Statutory Authority........................................................................................... 70

I. Executive Summary 

 The Renewable Fuel Standard (RFS) program began in 2007 following the 

requirements in Clean Air Act (CAA) section 211(o) which were implemented through 

the Energy Policy Act of 2005 (EPAct). The statutory requirements for the RFS program 

were subsequently modified through the Energy Independence and Security Act of 2007 

(EISA), resulting in the release of revised regulatory requirements on March 26, 20101

. 

In general, the transition from the RFS1 requirements of EPAct to the RFS2 requirements 

of EISA will occur on July 1, 2010. 

 EPA is required to determine and publish the applicable annual percentage 

standards for each compliance year by November 30 of the previous year. The 

determination of the applicable standards under RFS2 requires the EPA to conduct an indepth evaluation of the volume of qualifying cellulosic biofuel that can be supplied in the 

following year. If the projected volume of cellulosic biofuel production is less than the 

required volume specified in the statute, EPA must lower the required volume used to set 

the annual cellulosic biofuel percentage standard to the projected volume of production. 

We must also determine whether the advanced biofuel and/or total renewable fuel 

volumes should be reduced by the same or a lesser amount. Since these evaluations will 

be based on evolving information about emerging segments of the biofuels industry, and 

may result in the required volumes differing from those in the statute, we believe that a 

notice-and-comment rulemaking process is appropriate. Today's notice provides our 

evaluation of the projected production of cellulosic biofuel for 2011, and proposed 

percentage standards for compliance year 2011. We will complete our evaluation based 

on comments received in response to this proposal, the Production Outlook Reports due 

to the Agency on September 1, 2010, the estimate of projected biofuel volumes that the 

EIA is required to provide to EPA by October 31, and other information that becomes 

available, and will finalize the standards for 2011 by November 30, 2010. 

 Today's proposed rule does not include an assessment of the environmental 

impacts of the standards we are proposing for 2011. All of the impacts of the RFS2 

program were addressed in the RFS2 final rule published on March 26, 2010, including 

impacts of the biofuel standards specified in the statute. Today's rulemaking simply 

proposes the standards for 2011 whose impacts were already analyzed previously. 

 Today's notice also presents two proposed changes to the RFS2 regulations. The 

first would create a temporary and limited means for certain renewable fuel producers to 

 

1

 75 FR 14670 
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generate RINs after they have produced and sold renewable fuel. This proposed 

provision for "Delayed RINs" would apply only to those producers who use canola oil, 

grain sorghum, pulpwood, or palm oil to produce renewable fuel, and only if EPA 

determines that fuel pathways utilizing these feedstocks provide appropriate greenhouse 

gas reductions as compared to baseline fuels to enable EPA to list the pathways in Table 

1 to §80.1426. We are proposing that the provision for Delayed RINs would apply only 

to these four feedstocks because we would have included them in the final RFS2 rule if 

the lifecycle analyses had been completed in time. The greenhouse gas (GHG) lifecycle 

impacts of these four feedstocks are currently being analyzed as a supplement to the 

RFS2 final rule and are expected to be completed in 2010. The second proposed 

regulatory provision would establish criteria for EPA to use in determining whether to 

authorize renewable fuel producers using foreign-grown feedstocks to use an aggregate 

approach to compliance with the renewable biomass verification provisions, akin to that 

applicable to producers using crops and crop residue grown in the United States. Further 

discussion of both of these proposed provisions can be found in Section V. 

 Finally, we note that in the RFS2 final rule we also stated our intent to make two 

announcements each year: 

• Set the price for cellulosic biofuel waiver credits that will be made 

available to obligated parties in the event that we reduce the volume of 

cellulosic biofuel below the volume required by EISA. 

• Announce the results of our assessment of the aggregate compliance 

approach for verifying renewable biomass requirements for U.S. crops and 

crop residue, and our conclusion regarding whether the aggregate 

compliance provision will continue to apply. 

For both of these determinations EPA will use specific sources of data and a 

methodology laid out in the RFS2 final rule. We intend to present the results of both of 

these determinations in the final rule following today's proposal. 

 A. Statutory Requirements for Cellulosic Biofuel 

 The volumes of renewable fuel that must be used under the RFS2 program each 

year (absent an adjustment or waiver by EPA) are specified in CAA 211(o)(2). These 

volumes for 2011 are shown in Table I.A-1. 

Table I.A-1 

Required Volumes in the Clean Air Act for 2011 (bill gal) 

Actual Volume Ethanol Equivalent 

Volume 

Cellulosic biofuel 0.25 0.25 

Biomass-based diesel 0.80 1.20 

Advanced biofuel 1.35 1.35 
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Renewable fuel 13.95 13.95 

By November 30 of each year, the EPA is required under CAA 211(o) to determine and 

publish in the Federal Register the renewable fuel standards for the following year. 

These standards are to be based in part on transportation fuel volumes estimated by the 

Energy Information Administration (EIA) for the following year. The calculation of the 

percentage standards is based on the formulas in §80.1405(c) which express the required 

volumes of renewable fuel as a volume percentage of gasoline and diesel sold or 

introduced into commerce in the 48 contiguous states plus Hawaii. 

 The statute requires the EPA to determine whether the projected volume of 

cellulosic biofuel production for the following year is less than the minimum applicable 

volume shown in Table I.A-1. If this is the case, then the standard for cellulosic biofuel 

must be based upon the volume projected to be available rather than the applicable 

volume in the statute. In addition, if EPA reduces the required volume of cellulosic 

biofuel below the level specified in the statute, the Act also indicates that we may reduce 

the applicable volume of advanced biofuels and total renewable fuel by the same or a 

lesser volume. 

 As described in the final rule for the RFS2 program, we intend to examine EIA’s 

projected volumes and other available data including the Production Outlook Reports 

required under §80.1449 in making the determination of the appropriate volumes to 

require for 2011. Since the first set of Production Outlook Reports are not due until 

September 1, 2010, they were not available for today's proposal but will be considered 

for development of the final rule to be released by November 30, 2010. 

B. Assessment of 2011 Cellulosic Biofuel Volume 

 To estimate the volume of cellulosic biofuel that could be made available in the 

U.S. in 2011, we researched all potential production sources by company and facility. 

This included sources that were still in the planning stages, those that were under 

construction, and those that are already producing some volume of cellulosic ethanol, 

cellulosic diesel, or some other type of cellulosic biofuel. We considered all pilot and 

demonstration plants as well as commercial plants. From this universe of potential 

cellulosic biofuel sources we identified the subset that had a possibility of producing 

some volume of qualifying cellulosic biofuel for use as transportation fuel in 2011. We 

then conducted a rigorous process of contacting all of these producers to determine which 

ones were actually in a position to produce and make available any commercial volumes 

of cellulosic biofuel in 2011. Based on information gathered in this process, we 

estimated the maximum potentially available 2011 volumes. For the final rule, we will 

specify the projected available volume for 2011 that will be the basis for the percentage 

standard for cellulosic biofuel. To determine the projected available volume, we will 

consider factors such as the current and expected state of funding, the status of the 

technology and contracts for feedstocks, and progress towards construction and 
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production goals. A complete list of all the factors we expect to consider in this process 

is provided in Section II.A.5. 

 In our assessment we evaluated both domestic and foreign sources of cellulosic 

biofuel. Of the domestic sources, we estimated that seven facilities have the potential to 

make volumes of cellulosic biofuel available for transportation use in the U.S. in 2011. 

We also determined that one facility in Canada has the potential to export some cellulosic 

biofuel to the U.S. These facilities are listed in Table I.B-1 along with our estimate of the 

maximum potentially available volume. 

Table I.B-1 

Maximum Potentially Available Cellulosic Biofuel Plant Volumes for 2011 

Company Location Fuel type 

Maximum potentially 

available volume 

(million ethanolequivalent gallons) 

AE Advanced Fuels 

Keyes 

Keyes, CA Ethanol 0.5 

Agresti Biofuels Pike County, KY Ethanol 1 

Bell Bio-Energy Atlanta, GA Diesel 

feedstock 

11.9 

Cello Energy Bay Minette, AL Diesel 8.5 

DuPont Dansico Vonore, TN Ethanol 0.15 

Fiberight Blairstown, IA Ethanol 2.8 

Iogen Corporation Ottawa, Ont Ethanol 0.25 

KL Energy Corp / WBE Upton, WY Ethanol 0.4 

Total 25.5 

 The volumes in Table I.B-1 for each facility represent the volume that would be 

produced in 2011 based upon the owner's expected month of startup and an assumed 

period of production rampup for testing and process validation. However, none of the 

facilities we evaluated are currently producing cellulosic biofuel at the rates they project 

for 2011. Moreover, there are other uncertainties associated with each facility's projected 

volume that could result in less production volume in 2011 than the maximum potentially 

available values shown in Table I.B-1. These uncertainties include outstanding issues in 

areas such as technology, funding, and construction. Historical successes in meeting 

various past milestones also play a role in assessing the likelihood of meeting future 

milestones. A detailed discussion of these uncertainties is presented in Section II.A. 

Finally, the volumes that should be considered for setting the 2011 standard are those that 

result from valid cellulosic biofuel pathways in Table 1 to §80.1426. As described more 

fully in Section IV.A, some of the facilities in Table I.B-1 may use feedstocks that have 

not yet been subjected to lifecycle analyses to determine if the pathway meets the 

applicable GHG thresholds. 
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 Based on our preliminary assessment for this NPRM, we believe that we could 

justify a 2011 cellulosic biofuel volume requirement of at least 6.5 million ethanolequivalent gallons, and potentially as high as 25.5 million gallons. For the final rule we 

will use additional information that becomes available after publication of this proposal 

and a more precise assessment of the uncertainties associated with each facility to 

determine the projected available volume on which to base the cellulosic biofuel 

percentage standard for 2011. 

C. Advanced Biofuel and Total Renewable Fuel 

 As described in Section I.A above, the statute indicates that we may reduce the 

applicable volume of advanced biofuel and total renewable fuel if we determine that the 

projected volume of cellulosic biofuel production for 2011 falls short of the statutory 

volume of 250 million gallons. As shown in Table I.B-1, we are proposing a 

determination that this is the case. Therefore, we also needed to evaluate the need to 

lower the required volumes for advanced biofuel and total renewable fuel. 

 We first considered whether it appears likely that the required biomass-based 

diesel volume of 0.8 billion gallons can be met with existing biodiesel production 

capacity in 2011. As discussed in Section II.D, we believe that the 0.8 billion gallon 

standard can indeed be met. Since biodiesel has an Equivalence Value of 1.5, 0.8 billion 

physical gallons of biodiesel would provide 1.20 billion ethanol-equivalent gallons that 

can be counted towards the advanced biofuel standard of 1.35 billion gallons. Of the 

remaining 0.15 bill gallons, up to 0.026 bill gallons would be met with the proposed 

volume of cellulosic biofuel. Based on our analysis as described in Section II.C, there 

may be sufficient volumes of other advanced biofuels, such as imported sugarcane 

ethanol, additional biodiesel, or renewable diesel, such that the standard for advanced 

biofuel could remain at the statutory level of 1.35 billion gallons. However, uncertainty 

in the potential volumes of these other advanced biofuels coupled with the range of 

potential production volumes of cellulosic biofuel could provide a rationale for lowering 

the advanced biofuel standard. If we do not simultaneously lower the required volume 

for total renewable fuel, the result would be that additional volumes of conventional 

renewable fuel, such as corn-starch ethanol, would be produced, effectively replacing 

some advanced biofuels. In today's NPRM we are proposing that neither the required 

2011 volumes for advanced biofuel nor total renewable fuel be lowered below the 

statutory volumes. However, we request comment on whether the advanced biofuel 

and/or total renewable fuel volume requirements should be lowered if, as we propose, 

EPA lowers the required cellulosic biofuel volume from that specified in the Act. 

D. Proposed Percentage Standards 

 The renewable fuel standards are expressed as a volume percentage, and are used 

by each refiner, blender or importer to determine their renewable fuel volume obligations. 

The applicable percentages are set so that if each regulated party meets the percentages, 
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and if EIA projections of gasoline and diesel use are accurate, then the amount of 

renewable fuel, cellulosic biofuel, biomass-based diesel, and advanced biofuel used will 

meet the volumes required on a nationwide basis. To calculate the percentage standard 

for cellulosic biofuel for 2011, we have used a potential volume range of 6.5 - 25.5 

million ethanol-equivalent gallons (representing 5 - 17.1 million physical gallons). For 

the final rule, EPA intends to pick a single value from within this range to represent the 

projected available volume on which the 2011 percentage standard for cellulosic biofuel 

will be based. We are also proposing that the applicable volumes for biomass-based 

diesel, advanced biofuel, and total renewable fuel for 2011 will be those specified in the 

statute. These volumes are shown in Table I.D-1. 

Table I.D-1 

Proposed Volumes for 2011 

Actual Volume Ethanol Equivalent 

Volume 

Cellulosic biofuel 5 - 17.1 mill gal 6.5 - 25.5 mill gal 

Biomass-based diesel 0.80 bill gal 1.20 bill gal 

Advanced biofuel 1.35 bill gal 1.35 bill gal 

Renewable fuel 13.95 bill gal 13.95 bill gal 

 Four separate standards are required under the RFS2 program, corresponding to 

the four separate volume requirements shown in Table I.D-1. The specific formulas we 

use to calculate the renewable fuel percentage standards are contained in the regulations 

at §80.1405 and repeated in Section III.B.1. The percentage standards represent the ratio 

of renewable fuel volume to non-renewable gasoline and diesel volume. The projected 

volumes of gasoline and renewable fuels used to calculate the standards are provided by 

EIA's Short-Term Energy Outlook (STEO)2. The projected volume of transportation 

diesel used to calculate the standards is provided by EIA's 2010 Annual Energy Outlook 

(early release version).3 Because small refiners and small refineries are also regulated 

parties beginning in 20114, there is no small refiner/refinery volume adjustment to the 

2011 standard as there was for the 2010 standard. Thus, the increase in the percentage 

standards relative to 2010 appears smaller than would otherwise be the case, since more 

obligated parties will be participating in the program. The proposed standards for 2011 

are shown in Table I.D-2. Detailed calculations can be found in Section III. 

 

Table I.D-2 

 

2

 The March 2010 issue of STEO was used for today's proposal. We intend to use the October 2010 

version for the final rule. 

3

 EIA has recommended the use of the Annual Energy Outlook (AEO) rather than the Short Term Energy 

Outlook as a better representation of the estimated transportation sector diesel fuel use. We will use the 

most recent version of AEO in the final values of the standards. 

4

 The Department of Energy concluded that there is no reason to believe that any small refinery would be 

disproportionately harmed by inclusion in the proposed RFS2 program for 2011 and beyond. See DOE 

report “EPACT 2005 Section 1501 Small Refineries Exemption Study”, (January, 2009). We will revisit 

extensions to the exemption for small refiners and refineries if DOE revises their study and provides a 

different conclusion, or an individual small refinery is able to demonstrate that it will suffer a 

disproportionate economic hardship under the RFS program. 
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Proposed Percentage Standards for 2011 

Cellulosic biofuel 0.004-0.015% 

Biomass-based diesel 0.68% 

Advanced biofuel 0.77% 

Renewable fuel 7.95% 
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II. Volume Production and Import Potential for 2011 

 In order to project production volumes of cellulosic biofuel in 2011 for use in 

setting the percentage standards, we collected information on individual facilities that 

have the potential to produce qualifying volumes for consumption as transportation fuel, 

heating oil, or jet fuel in the U.S. in 2011. This section describes the potential volumes 

that we believe could be produced or imported in 2011 as well as the uncertainties 

associated with those volumes. The volumes listed in this section do not represent the 

projected available volume of cellulosic biofuel that will be used to finalize the cellulosic 

biofuel percentage standard for 2011. Rather, for today's NPRM we have assessed the 

maximum potentially available volume for 2011, which is intended to represent an upper 

bound of the volume of fuel that may be produced and made available. The production 

of cellulosic biofuel remains highly uncertain, and EPA expects that the volume of 

cellulosic biofuel used to set the 2011 percentage standard will be a lesser volume than 

this maximum potentially available volume. Section III describes the conversion of our 

maximum potentially available volumes for cellulosic biofuel into a range of percentage 

standards. 

 While the 2011 volume projections in today's proposal were based on our own 

assessment of the cellulosic biofuel industry, by the time we announce the final 2011 

volumes and percentage standards we will have additional information. First, in addition 

to comments in response to today's proposal, we will have updated and more detailed 

information about how the industry is progressing in 2010. Second, by September 1 all 

registered producers and importers of renewable fuel must submit Production Outlook 

Reports describing their expectations for new or expanded biofuel supply for the next 

five years, according to §80.1449. Finally, by October, 2010 the Energy Information 

Administration (EIA) is required by statute to provide EPA with an estimate of the 

volumes of transportation fuel, biomass-based diesel, and cellulosic biofuel projected to 

be sold or introduced into commerce in the U.S. in 2011. 

A. Cellulosic Biofuel 

The task of projecting the volume of cellulosic biofuels that will be produced in 

2011 is a difficult one. Currently there are no facilities consistently producing cellulosic 

biofuels for commercial sale. Announcements of new projects, changes in project plans, 

project delays, and cancellations occur with great regularity. Biofuel producers face not 

only the challenge of the scale up of innovative, first-of-a-kind technology, but also the 

challenge of securing funding in a difficult economy. 

 In order to project cellulosic biofuel production in 2011, EPA has tracked the 

progress of over 100 biofuel production facilities. From this list of facilities we used 

publically available information, as well as information provided by DOE and USDA, to 

determine which facilities were the most likely candidates to produce cellulosic biofuel 

and make it commercially available in 2011. Each of these companies was contacted by 

EPA in order to determine the current status of their facilities and discuss their 
DRAFT 5/18/10 

14

commercialization plans for the coming years. Our estimate of the maximum potentially 

available cellulosic biofuel production in 2011 is based on the information we received in 

conversations with these companies as well as our own assessment of the likelihood of 

these facilities successfully producing cellulosic biofuel in the volumes indicated. 

 A brief description of each of the companies we believe may produce cellulosic 

biofuel and make it commercially available can be found below. These companies have 

been grouped according to the type of biofuel they produce. For the purpose of setting 

the cellulosic biofuel standard for 2011 this is a convenient grouping, as the number of 

RINs generated per gallon of fuel produced is dependent on the type of fuel. A more in 

depth discussion of the technologies used to produce cellulosic biofuels can be found in 

Section IV. 

 In today's NPRM EPA is proposing a range, rather than a single value, for the 

required 2011 cellulosic biofuel volume. At a minimum, we believe that a volume of 6.5 

million gallons could be justified based on currently available information. This is the 

cellulosic biofuel volume that was required in 2010, and absent a waiver for some portion 

of this volume, producers will be aiming to meet it. Therefore, it is reasonable to project 

that this same volume could, at minimum, also be produced in 2011. 

 For a maximum potentially available cellulosic biofuel volume for 2011, we are 

proposing 25.5 million ethanol equivalent gallons, representing the highest volume of 

fuel that can reasonably be expected to be produced and made available based on current 

information. The rest of this section describes the analyses that were used as the basis for 

this maximum value. We will continue to gather more information to help inform our 

decision on the final cellulosic biofuel standard for 2011, and we will specify a single 

volume in the final rule that will be the basis for the cellulosic biofuel percentage 

standard for 2011. 

 1. Domestic Cellulosic Ethanol

Based on our assessment of the cellulosic biofuel industry we believe that there 

are five companies in the United States with the potential to produce cellulosic ethanol 

and make it commercially available in 2011. These companies are AE Biofuels, Agresti 

Biofuels, DuPont Danisco Cellulosic Ethanol, Fiberight, and KL Energy Corporation. 

This section will provide a brief description of each of these companies and our 

assessment of their potential fuel production in 2011. This section also provides a brief 

update on companies from whom we do not expect any commercial sales of 

transportation fuel in 2011 in the U.S. but were included in prior assessments. 

 AE Biofuels is a company that plans to convert corn cobs and corn stover to 

ethanol using an enzymatic hydrolysis. They plan to use an integrated process that 

converts both starch and cellulose to ethanol. In August 2008 they opened a 

demonstration plant in Butte, Montana to test their technology and gather information for 

their first commercial scale plant. AE Biofuels has reached a lease agreement with Cilion 
DRAFT 5/18/10 

15

to operate Cilion’s 55 MGY corn ethanol plant in Keyes, CA under the name AE 

Advanced Fuels Keyes. This facility has been idled since April 2009 and will require 

repairs before being operational. AE Biofuels plans to start up production with a starch 

feedstock in late-2010 and then begin to transition some production to cellulosic 

feedstock in mid-2011. AE Biofuels plans to eventually use up to 25% cellulosic 

feedstock for ethanol production in this facility. EPA projects that up to 0.5 million 

gallons of ethanol may be produced by this facility in 2011. 

 Agresti Biofuels plans to produce ethanol from separated municipal solid waste 

(separated MSW) at a facility in Pike County, Kentucky. Their process uses a gravity 

pressure vessel licensed from GeneSyst to crack the lignin in their feedstock and then a 

combination of weak bases and acids to convert the cellulose and hemicellulose into 

simple sugars for later fermentation into ethanol. Agresti plans to begin construction on 

their first production facility in Pike County sometime in the summer of 2010 and hope to 

be producing ethanol by the end of 2011. The full production capacity of this facility will 

be 20 million gallons of ethanol per year. Due to the fact that construction on this facility 

has not yet begun and production is not expected until late in 2011 EPA expects no more 

than 1 million gallons of cellulosic ethanol to be produced by Agresti Biofuels in 2011. 

 DuPont Danisco Cellulosic Ethanol (DDCE) began start up operations at a small 

demonstration facility in Vonore, Tennessee in early 2010. This facility has a maximum 

production capacity of 250,000 gallons of ethanol per year and uses an enzymatic 

hydrolysis process to convert corn cobs into ethanol. The main purpose of this facility is 

not to produce ethanol to be sold commercially, but rather to provide information for the 

future construction and optimization of larger, commercial scale cellulosic ethanol 

production facilities. DDCE have indicated that they do not intend to produce more than 

150,000 gallons of ethanol in 2011 from the Vonore facility. 

 Fiberight is another company planning to convert MSW to ethanol. Fiberight 

purchased a small corn ethanol plant in Blairstown, IA and has converted it to produce 

cellulosic ethanol. They use an enzymatic hydrolysis process, with enzymes provided by 

Novozymes, to convert the cellulosic waste materials to simple sugars and eventually to 

ethanol. Fiberight has a unique enzyme recycle and recovery process that allows them to 

affordably use high concentrations of enzymes to increase the speed and conversion rate 

of the cellulose to simple sugars. Fiberight plan to begin ethanol production in the 

summer of 2010 and ramp up to full production capacity of 5.7 million gallons of ethanol 

per year by late 2011. Based on company estimates, EPA projects Fiberight could 

produce as much as 2.8 million gallons of cellulosic ethanol in 2011. 

 The fifth company that EPA is aware of with the potential to produce cellulosic 

ethanol in 2011 is KL Energy Corporation. KL Energy has a small facility in Upton, 

Wyoming that uses an enzymatic hydrolysis process to convert wood chips and wood 

waste to ethanol. This facility has a maximum annual production volume of 1.5 million 

gallons and has been operational since the fall of 2007. Since KL Energy completed 

construction on this facility they have been slowly ramping up production and gathering 

information to optimize this and future ethanol production facilities. KL has informed 
DRAFT 5/18/10 

16

EPA that they intend to produce 400,000 gallons of cellulosic ethanol from their Upton, 

WY facility in 2011. 

 In addition to the five companies mentioned above, EPA is also tracking the 

progress of more than 70 ethanol production facilities in various stages ranging from 

construction to planning stages. Several of these companies, including Abengoa, 

BlueFire Ethanol, Coskata, Fulcrum, POET, and Vercipia all intend to begin the 

production and commercial sale of cellulosic ethanol in 2012. These facilities range in 

maximum production capacity from 10 to 100 million gallons of ethanol. EPA 

anticipates a significant increase in the production and sale of cellulosic ethanol in 2012, 

and strong continued growth in the following years. In addition, if any of these or other 

companies accelerates their production plans to make cellulosic biofuel available for 

commercial sale in 2011, we will take those volumes into account in our final rule. 

 2. Domestic Cellulosic Diesel

EPA is also aware of two companies in the United States with the potential of 

producing cellulosic diesel fuel in 2011. The first of these companies is Cello Energy. 

Cello Energy plans to use a catalytic depolymerization process to produce diesel fuel 

from wood chips and hay. Cello currently has a structurally complete facility in Bay 

Minette, Alabama with an annual production capacity of 20 million gallons of diesel per 

year. While having a structurally complete facility puts Cello ahead of many other 

potential biofuel producers they have yet to be able to produce biofuel at anywhere near 

the production capacity. They are currently assessing feedstock preparation and handling 

issues that must be resolved before they are able to again attempt start up and production 

at this facility. If these issues are successfully addressed EPA believes that Cello has the 

potential to produce up to 5 million gallons (8.5 million ethanol equivalent gallons) of 

cellulosic diesel fuel in 2011. 

 Another potential producer of cellulosic biofuel in 2011 is Bell Bio-Energy. Bell 

Bio-Energy uses proprietary organisms to convert waste materials to liquid fuels and 

compost in a single step. The company currently has an agreement in place for the sale 

of the compost they produce and are searching for a location for their first plant and a 

partner to supply the waste materials they intend to use as feedstock. The liquid fuel they 

produce is not a finished transportation fuel, but could be upgraded to jet or diesel fuel. 

Bell Bio-Energy is currently working with a refining company to analyze the fuel they 

produce and determine the extent of upgrading necessary for the fuel to qualify as 

transportation fuel. They plan to begin construction on their first facility, which will have 

an annual fuel production capacity of 14.4 million gallons per year, as soon as a suitable 

site and partner are found. The simplicity and low capital costs of Bell Bio-Energy’s 

single step production process allow them to construct plants very rapidly, in as little as 

six weeks. This would make it possible for Bell Bio-Energy to produce cellulosic biofuel 

in 2011 despite the fact that they have not yet begun construction on their first 

commercial scale facility. It is unclear when fuel will be produced at this facility, and 

whether it would qualify under the RFS2 program. If Bell Bio-Energy is successful in 
DRAFT 5/18/10 

17

producing and upgrading their fuel EPA estimates they could produce as much as 7 

million gallons (11.9 million ethanol equivalent gallons) of jet or diesel fuel in 2011. 

 EPA is also tracking the progress of 17 other facilities that plan to produce 

cellulosic diesel. Flambeau Rivers Biofuels, New Page, and Terrabon are planning on 

opening commercial scale cellulosic diesel facilities in 2012. Both Bell Bio-Energy and 

Cello have plans to build additional facilities if their initial projects are successful. As 

with cellulosic ethanol, cellulosic diesel production has the potential for rapid growth in 

2012 and the following years. 

 3. Other Domestic Cellulosic Biofuels

We are currently unaware of any companies in the United States planning on 

producing cellulosic biofuel other than ethanol and diesel and making it commercially 

available. EPA is currently tracking the efforts of 10 companies that plan to produce 

fuels such as gasoline, jet fuel, dimethyl ether (DME), and others. Many of these 

companies have reported that they are still developing their technologies and waiting for 

funding, and that they are not expecting to make any cellulosic fuel commercially 

available until 2012 at the earliest. There are several companies, such as Gevo and 

Virent, with small demonstration facilities who intend to produce other fuels from 

cellulosic feedstocks, but are currently optimizing their technology with sugar or starch 

feedstocks. EPA anticipates that in the future this may be a significant source of 

cellulosic biofuel, however we are only expecting cellulosic ethanol and diesel to be 

produced in 2011. 

 4. Imports of Cellulosic Biofuel

In addition to the companies located in the United States, EPA is also aware of 

two Canadian companies with the potential for cellulosic biofuel production in 2011. If 

this fuel was imported into the United States, these companies would be eligible to 

participate in the RFS2 program. Counting on cellulosic biofuel produced internationally 

in setting the 2011 standard brings with it the additional uncertainty associated with the 

fact that the fuel may be used locally rather than imported into the United States. 

 Iogen uses a steam explosion pre-treatment process followed by enzymatic 

hydrolysis to produce cellulosic ethanol from wheat, oat, and barley straw. They have a 

demonstration facility with an annual production capacity of 500,000 gallons of ethanol 

located in Ontario, Canada. This facility has been operational and producing small 

volumes of ethanol since 2004. So far all of the ethanol produced by this facility has 

been used locally and in racing and other promotional events. Iogen, however, is 

exploring the possibility of participating in the RFS2 program. If they do decide to 

import ethanol to the United States, EPA projects that they may provide as much as 

250,000 gallons of cellulosic ethanol in 2011 based on production volumes from previous 

years. 
DRAFT 5/18/10 

18

 Another Canadian company with the potential to produce cellulosic ethanol in 

2011 is Enerkem. Enerkem plans to use a thermo-chemical process to gasify separated 

MSW and other waste products and then use a catalyst to convert the synthesis (syn) gas 

into ethanol. Enerkem is currently finishing construction on a 1.3 million gallon per year 

facility in Westbury, Quebec and plans to begin producing ethanol in the summer of 

2010. They are also planning a 10 million gallon per year facility in Edmonton, Alberta, 

however production from this facility is not expected until 2012. Enerkem has informed 

EPA that they plan to market ethanol they produce locally, and have no intentions to 

import cellulosic ethanol into the United States. We are therefore not projecting any 

available cellulosic fuel from Enerkem in 2011. 

 While Canada may be the most likely source of imported cellulosic biofuels due 

to its close proximity, it is possible that cellulosic biofuels produced in other countries 

may be imported into the United States as well. Another potential source of cellulosic 

biofuel imports is Brazil, due to its established ethanol industry and history of importing 

ethanol into the United States. EPA is aware of several companies exploring the 

possibility of cellulosic biofuel production in Brazil; however none of these companies 

are likely to make cellulosic biofuels commercially available in the United States in 2011. 

With the exception of Iogen, as mentioned above, EPA has not projected imports of 

cellulosic biofuels from outside the United States in 2011. 

5. Summary of Volume Projections

 The information EPA has gathered on the potential cellulosic biofuel producers in 

2011, summarized in Section II.A above, allows us to project a maximum potentially 

available biofuel volume for each facility in 2011. After the appropriate ethanol 

equivalence value has been applied to the volumes of those facilities producing diesel 

fuel, the overall maximum potentially available volume of cellulosic biofuels for 2011 

can be calculated by summing the maximum potential of each facility. EPA is not 

proposing to set the 2011 cellulosic biofuel standard at this maximum potentially 

available volume, rather this is intended to serve as an upper bound. This information is 

summarized in Table II.A.5-1 below. 
DRAFT 5/18/10 

19

Table II.A.5-1 

Cellulosic Biofuel Maximum 2011 Potentially Available Volume 

Company Name Location Feedstock Fuel Capacity 

(MGY) 

Earliest 

Production 

Maximum 2011 

Available 

Potentially 

Volume (MG) 

Ethanol 

Equivalent 

Gallons 

(MG) 

Keyes AE Advanced Fuels Keyes, CA Corn, then 

stover 

Ethanol 20 June 2011 0.5 0.5 

Agresti Biofuels Pike County, 

KY 

MSW Ethanol 20 Oct. 2011 1 1 

Bell Bio-Energy Atlanta, GA MSW or other 

biomass cellulosic Feedstock 

Diesel 14.4 June 2011 7 11.9 

Cello Energy Bay Minette, 

AL 

Wood, hay Diesel 20 Online 5 8.5 

DuPont Daniscoa Vonore, TN Corn cobs, 

switchgrass then 

Ethanol 0.25 Online 0.15 0.15 

Fiberighta Blairstown, 

IA 

MSW Ethanol 6 April 2010 2.8 2.8 

Iogen Ottawa, 

Ontario barley straw 

Wheat, oat & Ethanol 0.5 Online 0.25 0.25 

KL Energya Upton, WY Wood Ethanol 1.5 Online 0.4 0.4 

Total 17.1 25.5 a Maximum Production/Import Potential represents company estimate 
DRAFT 5/18/10 

20

 It is important to note that this maximum potentially available volume of 17.1 

million gallons of cellulosic biofuel, or 25.5 million ethanol equivalent gallons, is not the 

volume on which the final 2011 cellulosic biofuel standard will be based. This number 

represents the maximum amount of fuel EPA believes could reasonably be expected to be 

produced or imported and made available for use as transportation fuel, heating oil, or jet 

fuel in 2011. It incorporates some reductions from the annual production capacity of 

each facility based on when the facilities anticipate fuel production will begin and 

assumptions regarding a ramp up period to full production. However, the history of the 

cellulosic biofuel industry has indicated that delays in achieving full production capacity 

in new facilities are not uncommon. Also, there are many other factors that increase the 

uncertainty of fuel production facilities being able to achieve their maximum potential 

production. These factors may include: 

• Difficulty/delays in securing necessary funding 

• Delays in permitting and/or construction 

• Difficulty in scale up, especially for 1st of their kind technologies 

• Volumes from pilot and demonstration plants may not be sold commercially 

• Not all feedstocks may qualify to produce cellulosic RINs; some still awaiting 

evaluation of lifecycle impacts 

• Likelihood that fuels produced internationally will be exported to the United 

States rather than consumed locally 

 Each of the facilities listed in Table II.A.5-1 may experience some of the 

difficulties listed above, and as a result may produce a volume of fuel less than that listed 

as their maximum 2011 potentially available volumel. Despite this uncertainty, EPA 

believes that the volume of cellulosic biofuel produced in 2011 will, at minimum, be able 

to meet or exceed the 2010 standard of 6.5 million ethanol equivalent gallons. However, 

we will have more detailed and accurate information for the final rule, including the first 

round of Production Outlook Reports, due on September 1, 20105 which will provide 

information from each producer or importer on the type or types of fuel they plan to make 

available, the volume of fuel, and the number of RINs they plan to generate for the next 

five calendar years6

. Therefore, in today's NPRM we are proposing a range of values, 

from a minimum of 6.5 million ethanol equivalent gallons to a maximum of 25.5 million 

ethanol equivalent gallons for the 2011 cellulosic biofuel standard. As time progresses 

and we are able to track whether or not the cellulosic biofuels producers are able to meet 

the construction and ramp up schedules they have presented, we will have a better idea of 

the appropriate volume of fuel that we can reasonably expect to be produced and made 

commercially available. Additionally, each year by October 31 EIA is required to 

provide an estimate of the volume of cellulosic biofuel they expect to be sold or 

introduced into commerce in the United States in the following year. EPA will consider 

this information as well when finalizing a single volume for use in setting the 2011 

cellulosic biofuel standard. 

 

5

 In future years, Production Outlook Reports will be due on March 1. As a result, they may be considered 

during development of the NPRM in year 2011 and beyond. 

6

 For more information on the annual production outlook reports see § 80.1449 of the RFS2 regulations. 
DRAFT 5/18/10 

21

 Although we are currently projecting that the maximum potentially available 

volume of cellulosic biofuel in 2011 will be 25.5 million gallons, we expect that volumes 

of cellulosic biofuel will increase rapidly in the years following 2011. As stated before, 

we are aware of more than 100 companies that are actively investigating or making plans 

to produce cellulosic biofuel in the near future. Many of these companies intend to begin 

construction in 2011 or 2012. We will be monitoring these companies carefully as we 

project the potential volumes of cellulosic biofuel for years 2012 and beyond. 

B. Potential Limitations 

 In addition to production capacity, a variety of other factors have the potential to 

limit the amount of cellulosic biofuel that can be produced and used in the U.S. For 

instance, there may be limitations in the availability of qualifying cellulosic feedstocks at 

reasonable prices. Most of the cellulosic biofuel producers that we project will produce 

commercial volumes in 2011 have indicated that they will use some type of cellulosic 

waste, such as separated municipal solid waste, wastes from the forestry industry, and 

agricultural residues. Based on the analyses of cellulosic feedstock availability in the 

RFS2 final rule, we believe that there will be significantly more than enough sources of 

these feedstocks for 2011. For producers that intend to use dedicated energy crops, we 

do not believe that the availability of existing cropland will limit production in 2011. We 

plan to continue to evaluate the availability of valid feedstocks in future years as the 

required volumes of cellulosic biofuel increase. 

 Another factor that has the potential to limit the amount of renewable fuel that can 

be produced and used in the U.S. is distribution and storage capacity. In the longer term, 

most biofuels are expected to be produced in the heartland of the country and then be 

shipped towards the coasts, flowing roughly in the opposite direction of petroleum-based 

fuels. The physical and chemical nature of many of these biofuels may limit the extent to 

which they can be shipped and/or stored fungibly with petroleum-based fuels. As a 

result, new and expanded rail, barge and tank truck transport will need to be put in place. 

Dedicated biofuels pipelines are also being investigated. However, for 2011 the volumes 

of cellulosic biofuel are small enough that long-distance transport will be unnecessary; 

with the exception of foreign-produced biofuels, much of the cellulosic biofuel volumes 

can be consumed in regions close to their production facilities. We also expect existing 

distribution and storage capacity to be sufficient to accommodate the small increase in 

cellulosic biofuel volumes in 2011. 

C. Advanced Biofuel and Total Renewable Fuel 

 Under CAA 211(o)(7)(D)(i), EPA has the flexibility to reduce the applicable 

volume of the advanced biofuel and total renewable fuel requirements in the event that 

the projected volume of cellulosic biofuel is determined to be below the volume specified 

in the statute. As described in Section II.A above, even the largest potential volumes of 

cellulosic biofuel supply for 2011 are significantly below the statutory volume of 250 
DRAFT 5/18/10 

22

million gallons. Therefore, we must consider whether and to what degree to lower the 

advanced biofuel and total renewable fuel standards for 2011. 

 As described in the RFS2 final rule, we believe it may be appropriate to allow 

excess advanced biofuels to make up some or all of the shortfall in cellulosic biofuel. 

This could include excess biomass-based diesel, sugarcane ethanol, or other biofuels 

categorized as advanced biofuel. We believe that Congress wanted to encourage the 

development of advanced renewable fuels and allow in appropriate circumstances for the 

use of additional volumes of those fuels in the event that the projected volume of 

cellulosic biofuel falls below the statutory mandate. 

 If we were to maintain the advanced biofuel and total renewable fuel volume 

requirements at the levels specified in the statute, we estimate that 125 - 144 million 

ethanol-equivalent gallons of additional advanced biofuels would be needed, depending 

on the standard we set for cellulosic biofuel. See Table II.C-1. 

Table II.C-1 

Projected Impact of Cellulosic Volume on Use of Other Biofuels in 2011 (mill gallons) 

 Ethanol-Equivalent 

Volume 

Physical Volume 

Total renewable fuel 

Conventional renewable fuela

13,950 

12,600 

13,500 - 13,549 

12,600 

Total advanced biofuel 1,350 900 - 949 

Cellulosic biofuel 

Biomass-based diesel 

Other advanced biofuelb

6.5 - 25.5 

1200 

125 - 144 

5 - 17.1 

800 

83c - 144d

a

 Predominantly corn-starch ethanol

b

 Rounded to nearest million gallons for simplicity 

c Lowest volume of other advanced biofuel assumes cellulosic biofuel standard is based 

on 25.5 mill gallons and only excess biodiesel (with an equivalence value (EV) of 1.5) is 

used to fill the need for other advanced biofuel 

d Highest volume of other advanced biofuel assumes cellulosic biofuel standard is based 

on 6.5 mill gallons and only imported sugarcane ethanol (with an EV of 1.0) is used to 

fill the need for other advanced biofuel 

 To determine if there are likely to be sufficient volumes of imported sugarcane 

ethanol and/or excess biodiesel to meet the need for 125 - 144 million gallons of other 

advanced biofuel, we examined historical data on ethanol imports and EIA projections 

for 2011. For instance, as shown in Table II.C-2 below, recent annual import volumes of 

ethanol were higher than what would be needed in 2011. 
DRAFT 5/18/10 

23

Table II.C-2 

Historical Imports of Ethanol (mill gallons)7

2007 

2008 

2009 

439 

530 

194 

However, EIA's projections for 2011 suggest that there may be insufficient volumes of 

imported sugarcane ethanol and excess biodiesel production to make up for our proposed 

reduction in the required volume of cellulosic biofuel. See Table II.C-3. 

 

Table II.C-3 

EIA Projected Imported Ethanol and Biodiesel Availability in 2011 (mill gallons)8

Imported ethanol 32 

Total domestic biodiesel production 

Biodiesel needed to meet biomass-based diesel standard 

Excess biodiesel 

860 

800 

60 

Further discussion of the potential availability of biomass-based diesel in 2011 can be 

found in the next Section II.D below. 

 Based on these projections, there would be a total of 60 million gallons of excess 

biodiesel production (90 million gallons ethanol-equivalent), plus another 32 million 

gallons of imported sugarcane ethanol. The total would therefore be 122 million gallons 

ethanol-equivalent. Since we are projecting that the need for other advanced biofuel 

would be in the range of 125 - 144 million gallons depending on the cellulosic biofuel 

standard that we set, 122 million gallons may not be sufficient. However, the projections 

in Table II.C-3 do not account for other potential sources of advanced biofuels. For 

instance, California's Low Carbon Fuel Standard may compel some refiners to import 

additional volumes of sugarcane ethanol from Brazil into California, and these same 

volumes could count towards the federal RFS2 program as well. There may also be other 

types of advanced biofuel not included in the EIA projections that could help meet our 

projected shortfall. These other advanced biofuels include, for instance, renewable fuels 

made from separated yard and food waste. Finally, the values in Table II.C-3 do not 

account for the potentially higher value for imported sugarcane ethanol and biodiesel and 

the additional market demand for these renewable fuels that would be created if we chose 

not to lower the advanced biofuel standard for 2011. Given these factors, we believe that 

there are likely to be sufficient volumes of other advanced biofuels such that the 

advanced biofuel standard need not be lowered below 1.35 billion gallons. Thus, we are 

proposing to leave the required volume of advanced biofuel for 2011 at 1.35 billion 

gallons. Nevertheless, we request comment on whether we should lower the advanced 

biofuel standard. If we do lower the advanced biofuel standard, we request comment on 

the degree to which we should take into account other potential sources of advanced 

biofuel as discussed above. 

 

7

 "Monthly U.S. Imports of Fuel Ethanol," EIA, released 4/8/2010 

8

 EIA STEO, March 2010, Table 8 
DRAFT 5/18/10 

24

 If we lower the cellulosic biofuel standard, we would also need to determine if the 

total renewable standard should be lowered. Lowering both the advanced biofuel 

standard and the total renewable fuel standard by the same amount would mean that the 

expected amount of conventional renewable fuel use, such as corn-ethanol, would 

remained unchanged at 12,600 million gallons ethanol equivalent, the same as shown in 

Table II.C-1. 

 If instead we were to lower the advanced biofuel standard but retain the total 

renewable fuel standard at 13,950 million gallons, then we would expect the use of 

conventional renewable fuels such as corn ethanol to increase. For instance, if we were 

to lower the advanced biofuel standard by 144 million gallons to 1206 million gallons, 

we would expect the amount of corn-ethanol used would increase by 144 million gallons 

in order to satisfy the total renewable fuel standard of 13,950 million gallons. According 

to EIA, projected volumes of corn-ethanol are indeed expected to be higher than 12,600 

million gallons in 2011, producing an excess of 490 million gallons. See Table II.C-4. 

Table II.C-4 

Projected Excess Corn Ethanol in 2011 (mill gallons) 

Total domestic corn ethanol production9

Corn-ethanol needed to meet total renewable fuel standard 

Excess corn ethanol 

13,090 

12,600 

490 

However, the market potential for ethanol in the U.S. is also a function of the ethanol 

blender's tax credit, set to expire at the end of 2010. If this tax credit is not renewed, the 

excess ethanol volume shown in Table II.C-4 may be smaller. Thus, while we are 

proposing that the required volume of total renewable fuel for 2011 be set at the statutory 

level of 13.95 billion gallons, we request comment on whether the total renewable fuel 

standard should be lowered. 

D. Biomass-Based Diesel 

 While the statutory requirement that we project volumes of cellulosic biofuel for 

next year does not explicitly apply to biomass-based diesel as well, there are two other 

statutory requirements that compel us to investigate current and potential future volumes 

of biomass-based diesel. First, the Clean Air Act provides limited waiver authority 

specific to biomass-based diesel under 211(o)(7)(E) if a significant renewable feedstock 

disruption or other market circumstance would make the price of biomass-based diesel 

fuel increase significantly. Second, as described more fully in Section II.C above, we 

must determine whether the required volumes of advanced biofuel and/or total renewable 

fuel should be reduced at the same time that we reduce the required volume of cellulosic 

biofuel. The amount of biomass-based diesel that we project can be available will 

directly affect our consideration of adjustments to the volumetric requirements for 

advanced biofuel and total renewable fuel. 

 

9

 EIA STEO, March 2010, Table 8 
DRAFT 5/18/10 

25

 To project biodiesel production volumes for 2011, we examined both production 

capacity of the industry as well as actual recent production rates. As of April 2010, the 

aggregate production capacity of biodiesel plants in the U.S. was estimated at 2.2 billion 

gallons per year across approximately 137 facilities. 10 Biodiesel production for calendar 

year 2009, according to the most recently available information, was 540 million gallons, 

with an estimated 351 mill gallons (or 65%) being used domestically. Domestic 

production rates in the second half of 2009 increased above production rates in the first 

half as economic conditions improved, to an annualized rate of around 646 mill gal per 

year. Meanwhile, exports appeared to stabilize at an annualized rate of about 242 mill 

gal per year, after recovering from changes in European import regulations early in the 

year. These trends for 2009 are shown in Figure II.D-1. 

Figure II.D-1 

U.S. Biodiesel Production and Export Trends for 2009. 11

0

10

20

30

40

50

60

70

1 2 3 4 5 6 7 8 9 10 11 12

Month, 2009

MMgal

Production Exports

 In the early part of 2010, industry reports of monthly biodiesel production 

indicated that production rates have dropped below the 2009 average. The most likely 

cause is the expiration of the biodiesel tax credit. However, EIA's Short-Term Energy 

Outlook projects that, for the year as a whole, average monthly biodiesel production rates 

in 2010 will actually exceed those in 2009. The projected increase in monthly biodiesel 

production rates later in 2010 is consistent with the fact that obligated parties are not 

required to demonstrate compliance with the 2010 biomass-based diesel volume 

requirement of 1.15 billion gallons until February 28, 2011. For development of our final 

rule setting the standards for 2011, we will have more complete data with which to 

 

10 Figures taken from National Biodiesel Board list of operating plants as of April 5, 2010. 

11 Data taken from Energy Information Administration Monthly Energy Review, Table 10.4, March 2010. 
DRAFT 5/18/10 

26

evaluate the progress of the biodiesel industry in meeting the 2010 volume mandate and 

thus its preparedness for 2011. 

 In order to meet a 2011 biomass-based diesel volume requirement of 0.8 billion 

gallons to be consumed in the United States, the biodiesel industry will need to produce 

approximately 725 million gal of fuel. This value accounts for the production of 75 

million gallons of renewable diesel at one renewable diesel facility in Geismar, 

Louisiana, set to begin operations later this year.12 Assuming imports and exports 

continue at a rate equivalent to that in the second half of 2009, biodiesel production in the 

U.S. would need to total approximately 900 million gal in 2011. While this production 

rate would be about 10% higher than the production rate projected by EIA for the second 

half of 2010, it would be significantly lower than the current 2.2 billion gallon biodiesel 

production capacity of the industry. Based on information from the biodiesel industry, 

we believe that idled facilities can be brought back into production in time to meet the 

2011 requirements for biomass-based diesel. Moreover, as shown in Table II.C-3, EIA is 

projecting that biodiesel availability will in fact exceed the minimum volume needed to 

meet the biomass-based diesel standard in 2011. 

 Finally, we believe that there will be sufficient sources of qualifying renewable 

biomass to meet the needs of the biodiesel industry in 2011. The largest sources of 

feedstock for biodiesel in 2011 are expected to be soy oil, rendered fats, and potentially 

some corn oil extracted during production of fuel ethanol, as this technology continues to 

proliferate. Moreover, comments we received from a large rendering company after the 

May 2009 RFS2 proposed rule suggest that there will be adequate fats and greases 

feedstocks to supply biofuels production as well as other historical uses. 13

 

12 Project status updates are available via the Syntroleum website, http://dynamicfuelsllc.com/wp-news/ 

13 See Federal Register v.74 n.99 p.24903. Comments are available in docket EPA-HQ-OAR-2005-0161. 
DRAFT 5/18/10 

27

III. Proposed Percentage Standards for 2011 

A. Background 

 The renewable fuel standards are expressed as a volume percentage, and are used by 

each refiner, blender or importer to determine their renewable volume obligations (RVO). 

Since there are four separate standards under the RFS2 program, there are likewise four 

separate RVOs applicable to each obligated party. Each standard applies to the sum of all 

gasoline and diesel produced or imported. The applicable percentage standards are set so 

that if each regulated party meets the percentages, then the amount of renewable fuel, 

cellulosic biofuel, biomass-based diesel, and advanced biofuel used will meet the volumes 

required on a nationwide basis. 

 As discussed in Section II.A.5, we are proposing a required volume of cellulosic 

biofuel for 2011 in the range of 5 - 17.1 million gallons (6.5 - 25.5 million ethanol 

equivalent gallons). The single volume we select for the final rule will be used as the 

basis for setting the percentage standard for cellulosic biofuel for 2011. We are also 

proposing that the advanced biofuel and total renewable fuel volumes would not be 

reduced below the statutory requirements. The proposed 2011 volumes used to 

determine the four percentage standards are shown in Table III.A-1. 

Table III.A-1 

Proposed Volumes for 2011 

Actual Volume Ethanol Equivalent 

Volume 

Cellulosic biofuel 5 - 17.1 mill gal 6.5 - 25.5 mill gal 

Biomass-based diesel 0.80 bill gal 1.20 bill gal 

Advanced biofuel 1.35 bill gal 1.35 bill gal 

Renewable fuel 13.95 bill gal 13.95 bill gal 

 

 The formulas used in deriving the annual renewable fuel standards are based in 

part on an estimate of combined gasoline and diesel volumes, for both highway and 

nonroad uses, for the year in which the standards will apply. Producers of other 

transportation fuels, such as natural gas, propane, and electricity from fossil fuels, are not 

subject to the standards. Since the standards apply to producers and importers of gasoline 

and diesel, these are the transportation fuels used to set the standards, and then again to 

determine the annual volume obligations of an individual producer or importer. 

B. Calculation of Standards 

 1. How Are the Standards Calculated?

The following formulas are used to calculate the four percentage standards 

applicable to producers and importers of gasoline and diesel (see §80.1405): 
DRAFT 5/18/10 

28

Gi − RGi + GSi − RGSi − GEi + Di − RDi + DSi − RDSi − DEi

= ×

( ) ( ) ( ) ( )

RFV Std 100% CB, i

CB, i

Gi − RGi + GSi − RGSi − GEi + Di − RDi + DSi − RDSi − DEi

× = ×

( ) ( ) ( ) ( )

RFV 1.5 Std 100% BBD, i 

BBD, i

Gi − RGi + GSi − RGSi − GEi + Di − RDi + DSi − RDSi − DEi

= ×

( ) ( ) ( ) ( )

RFV Std 100% AB, i

AB, i

Gi − RGi + GSi − RGSi − GEi + Di − RDi + DSi − RDSi − DEi

= ×

( ) ( ) ( ) ( )

RFV Std 100% RF, i

RF, i

Where 

StdCB,i = The cellulosic biofuel standard for year i, in percent. 

StdBBD,i = The biomass-based diesel standard (ethanol-equivalent basis) for year i, in 

percent. 

StdAB,i = The advanced biofuel standard for year i, in percent. 

StdRF,i = The renewable fuel standard for year i, in percent. 

RFVCB,i = Annual volume of cellulosic biofuel required by section 211(o) of the 

Clean Air Act for year i, in gallons.

RFVBBD,i = Annual volume of biomass-based diesel required by section 211(o) of the 

Clean Air Act for year i, in gallons. 

RFVAB,i = Annual volume of advanced biofuel required by section 211(o) of the 

Clean Air Act for year i, in gallons. 

RFVRF,i = Annual volume of renewable fuel required by section 211(o) of the Clean 

Air Act for year i, in gallons. 

Gi = Amount of gasoline projected to be used in the 48 contiguous states and 

Hawaii, in year i, in gallons. 

Di = Amount of diesel projected to be used in the 48 contiguous states and 

Hawaii, in year i, in gallons. 

RGi = Amount of renewable fuel blended into gasoline that is projected to be 

consumed in the 48 contiguous states and Hawaii, in year i, in gallons. 
DRAFT 5/18/10 

29

RDi = Amount of renewable fuel blended into diesel that is projected to be 

consumed in the 48 contiguous states and Hawaii, in year i, in gallons. 

GSi = Amount of gasoline projected to be used in Alaska or a U.S. territory in 

year i if the state or territory opts-in, in gallons. 

RGSi = Amount of renewable fuel blended into gasoline that is projected to be 

consumed in Alaska or a U.S. territory in year i if the state or territory 

opts-in, in gallons. 

DSi = Amount of diesel projected to be used in Alaska or a U.S. territory in year 

i if the state or territory opts-in, in gallons. 

RDSi = Amount of renewable fuel blended into diesel that is projected to be 

consumed in Alaska or a U.S. territory in year i if the state or territory 

opts-in, in gallons. 

GEi = The amount of gasoline projected to be produced by exempt small 

refineries and small refiners in year i, in gallons, in any year they are 

exempt per §§80.1441 and 80.1442, respectively. For 2011, this value is 

zero. See further discussion in Section III.B.2 below. 

DEi = The amount of diesel projected to be produced by exempt small refineries 

and small refiners in year i, in gallons, in any year they are exempt per 

§§80.1441 and 80.1442, respectively. For 2011, this value is zero. See 

further discussion in Section III.B.2 below. 

 The four separate renewable fuel standards for 2011 are based on the 49-state 

gasoline and diesel consumption volumes projected by EIA. The Act requires EPA to 

base the standards on an EIA estimate of the amount of gasoline and diesel that will be 

sold or introduced into commerce for that year. The projected volume of gasoline used to 

calculate the final percentage standards will continue to be provided by the October issue 

of EIA's Short-Term Energy Outlook (STEO). For the purposes of this proposal, we 

have used the March 2010 issue of STEO. The projected volume of transportation diesel 

used to calculate the final percentage standards will be provided by the most recent 

Annual Energy Outlook (AEO). For the purposes of this proposal, we have used the 

Early Release version of AEO2010. Gasoline and diesel volumes are adjusted to account 

for renewable fuel contained in the EIA projections. Beginning in 2011, gasoline and 

diesel volumes produced by small refineries and small refiners are not exempt, and thus 

there is no adjustment to the gasoline and diesel volumes in today's proposal to account 

for such an exemption, as there has been in past years. However, as discussed more fully 

in Section III.B.2 below, depending upon the results of a Congressionally-mandated DOE 

study, it is possible that the exemption for gasoline and diesel volumes produced by small 

refineries and small refiners may be extended. In addition, EPA may extend the 

exemption for individual small refineries on a case-by-case basis if they demonstrate 

disproportionate economic hardship. 
DRAFT 5/18/10 

30

As finalized in the March 26, 2010 RFS2 rule, the standards are expressed in 

terms of energy-equivalent gallons of renewable fuel, with the cellulosic biofuel, 

advanced biofuel, and total renewable fuel standards based on ethanol equivalence and 

the biomass-based diesel standard based on biodiesel equivalence. However, all RIN 

generation is based on ethanol-equivalence. More specifically, the RFS2 regulations 

provide that production or import of a gallon of biodiesel will lead to the generation of 

1.5 RINs. In order to ensure that demand for 0.8 billion physical gallons of biomassbased diesel will be created in 2011, the calculation of the biomass-based diesel standard 

provides that the required volume be multiplied by 1.5. The net result is a biomass-based 

diesel gallon being worth 1.0 gallons toward the biomass-based diesel standard, but worth 

1.5 gallons toward the other standards. 

 The levels of the percentage standards would be reduced if Alaska or a U.S. 

territory chooses to participate in the RFS2 program, as gasoline and diesel produced in 

or imported into that state or territory would then be subject to the standard. Neither 

Alaska nor any U.S. territory has chosen to participate in the RFS2 program at this time, 

and thus the value of the related terms in the calculation of the standards is zero. 

 Note that the terms for projected volumes of gasoline and diesel use include 

gasoline and diesel that has been blended with renewable fuel. Because the gasoline and 

diesel volumes described above include renewable fuel use, we must subtract the total 

renewable fuel volume from the total gasoline and diesel volume to get total nonrenewable gasoline and diesel volumes. The values of the variables described above are 

shown in Table III.B.1-1. Terms not included in this table have a value of zero. 

Table III.B.1-1 

Values for Terms in Calculation of the Standards (bill gal) 

Term Value 

RFVCB,2011 0.0065 - 0.0255 

RFVBBD,2011 0.80 

RFVAB,2011 1.35 

RFVRF,2011 13.95 

G2011 139.66 

D2011 50.01 

RG2011 13.38 

RD2011 0.74 

Using the volumes shown in Table III.B.1-1, we have calculated the proposed 

percentage standards for 2011 as shown in Table III.B.1-2. 
DRAFT 5/18/10 

31

Table III.B.1-2 

 Proposed Percentage Standards for 2011 

Cellulosic biofuel 0.004-0.015% 

Biomass-based diesel 0.68% 

Advanced biofuel 0.77% 

Renewable fuel 7.95% 

2. Small Refineries and Small Refiners

In CAA section 211(o)(9), enacted as part of EPAct, Congress provided a 

temporary exemption to small refineries (those refineries with a crude throughput of no 

more than 75,000 barrels of crude per day) through December 31, 2010. In RFS1, we 

exercised our discretion under section 211(o)(3)(B) and extended this temporary 

exemption to the few remaining small refiners that met the Small Business 

Administration’s (SBA) definition of a small business (1,500 employees or less 

company-wide) but did not meet the statutory small refinery definition as noted above. 

Because EISA did not alter the small refinery exemption in any way, the RFS2 program 

regulations exempt gasoline and diesel produced by small refineries and small refiners in 

2010 from the renewable fuels standard (unless the exemption was waived), see 40 CFR 

§80.1141. 

Under the RFS program, Congress has provided two ways that small refineries 

can receive a temporary extension of the exemption beyond 2010. One is based on the 

results of a study conducted by the Department of Energy (DOE) to determine if small 

refineries would face a disproportionate economic hardship under the RFS program. The 

other is based on EPA determination of disproportionate economic hardship on a case-bycase basis in response to refiner petitions. 

In January 2009, DOE issued a Small Refineries Exemption Study which did not 

find that small refineries would face a disproportionate economic hardship under the RFS 

program. The conclusions were based in part on the expected robust availability of RINs 

and EPA’s ability to grant relief on a case-by-case basis. Subsequently, Congress 

directed DOE to complete a reassessment and issue a revised report by June 30, 2010. 

DOE had not revised its study at the time of the RFS2 final rulemaking nor at the time of 

this writing. Additionally, we have not received any requests for relief on a case-by-case 

basis from any small refinery. If DOE prepares a revised study, and the results of that 

study show a disproportionate economic hardship for any small refineries under the RFS 

program, we will take appropriate action to extend the exemption. However, until and 

unless a DOE study supporting an extension to the temporary exemption for small 

refineries beyond 2010 is used, or any petitions to EPA from individual small refineries 

claiming disproportionate economic hardship are approved, we are not proposing to 

change the required inclusion of small refineries and small refiners in the RFS2 program 

beginning with the 2011 compliance period. 
DRAFT 5/18/10 

32

IV. Cellulosic Biofuel Technology Assessment 

 In projecting the volumes of cellulosic biofuel for 2011, we conducted a technical 

assessment of the production technologies that are under consideration by the broad 

universe of companies we investigated. Many of these companies are still in the research 

phase, resolving outstanding issues with specific technologies, and/or in the design phase 

to implement those technologies for the production of commercial-scale volumes of 

cellulosic biofuel. A subset of the companies we investigated have moved beyond the 

research and design phase and are actively preparing for production. This smaller group 

of companies formed the basis for our projection of potential 2011 volumes of cellulosic 

biofuel. 

 This section discusses the full range of cellulosic biofuel technologies being 

considered among producers, with reference to those individual companies that are 

focusing on each technology and those we project will be most likely to use those 

technologies to produce cellulosic biofuel in 2011. 

A. What Pathways are Valid for the Production of Cellulosic Biofuel? 

 In determining the appropriate volume of cellulosic biofuel on which to base the 

percentage standard for 2011, we must ensure that the production facilities we use as the 

basis for this volume are using fuel pathways that are valid for the production of 

cellulosic biofuel. In general this means that each facility's pathway (combination of 

feedstock, production process, and fuel type) must be included in Table 1 to §80.1426 

and be assigned a D code of either 3 or 7. As of this writing, there are three valid 

pathways available as shown in Table IV.A-1 below. 

Table IV.A-1 

Cellulosic Biofuel Pathways for Use in Generating RINs 

Fuel Type Feedstock Production Process 

Requirements 

D-Code 

Ethanol Cellulosic Biomass 

from agricultural 

residues, slash, forest 

thinnings and forest 

product residues, 

annual covercrops; 

switchgrass, and 

miscanthus; cellulosic 

components of 

separated yard wastes; 

cellulosic components 

of separated food 

Any 3 

(cellulosic 

biofuel) 
DRAFT 5/18/10 

33

wastes; and cellulosic 

components of 

separated MSW 

Cellulosic 

Diesel, Jet Fuel 

and Heating Oil 

Cellulosic Biomass 

from agricultural 

residues, slash, forest 

thinnings and forest 

product residues, 

annual covercrops, 

switchgrass, and 

miscanthus; cellulosic 

components of 

separated yard wastes; 

cellulosic components 

of separated food 

wastes; and cellulosic 

components of 

separated MSW 

Any 7 

(cellulosic 

diesel) 

Cellulosic 

Naphtha 

Cellulosic Biomass 

from agricultural 

residues, slash, forest 

thinnings and forest 

product residues, 

annual covercrops, 

switchgrass, and 

miscanthus; cellulosic 

components of 

separated yard wastes; 

cellulosic components 

of separated food 

wastes; and cellulosic 

components of 

separated MSW 

Fischer-Tropsch 

process 

3 

(cellulosic 

biofuel) 

Of the eight facilities that we currently believe could contribute to the volume of 

commercially available cellulosic biofuel in 2011, six would produce ethanol from 

cellulosic biomass and two would produce diesel from cellulosic biomass. None of the 

facilities we have evaluated would produce cellulosic naphtha through a Fischer-Tropsch 

process. 

 Two of the facilities shown in Table II.A.5-1, Cello Energy and KL Energy, 

intend to use wood as the primary feedstock. The only types of wood that are currently 
DRAFT 5/18/10 

34

allowed as a valid feedstock are those derived from various types of waste. If either of 

these two companies choose to use trees from a tree plantation instead of qualifying 

waste wood, its pathway would not fall into the any of the pathways currently listed in 

Table 1 to §80.1426. However, as described more fully in Section V.A, we are currently 

evaluating the lifecycle GHG impacts of biofuel made from pulpwood, including wood 

from tree plantations. If such a pathway is determined to meet the 60% GHG threshold 

required for cellulosic biofuel, we expect that it will be added to Table 1 to §80.1426 in 

time to apply to fuel produced in 2011. For the purposes of this proposal, we have 

chosen to retain the volumes from these two companies in our projections of 2011 

cellulosic biofuel volume, but we will revisit this issue for the final rule. 

B. Cellulosic Feedstocks 

Cellulosic biofuel technologies are different from other biofuel technologies 

because they convert the cellulose and other very difficult to convert compounds into 

biofuels. Unlike grain feedstocks where the major carbohydrate is starch (very simply 

combined sugars), lignocellulosic biomass is composed mainly of cellulose (40-60 %) 

and hemicellulose (20-40 %).14 Cellulose and hemicellulose are made up of sugars 

linked together in long chains called polysaccharides. Once hydrolyzed, they can be 

fermented into ethanol. Most all the remainder of cellulosic feedstocks consists of lignin, 

a complex polymer which serves as a stiffening and hydrophobic (water-repelling) agent 

in cell walls. Currently, lignin cannot be fermented into ethanol, but could be burned as a 

by-product to generate electricity. Thermochemical, pyrolysis and depolymerization 

processing, however, can convert some or even most of the lignin, in addition to the 

cellulosic and hemicellulose, into biofuels.

 

C. Emerging Technologies 

 When evaluating the array of biofuel technologies which could produce one or 

more fuels from cellulose that could qualify under RFS2, we found that it is helpful to 

organize them into fuel technology categories. Organizing them into categories eases the 

task of understanding the technologies, and also simplifies our understanding of the costs 

and lifecycle impacts of these technologies because similar technologies likely have 

similar cost and lifecycle impacts. The simplest organization is by the fuel produced. 

However, we frequently found that additional subdivisions were also helpful. Table 

IV.C-1 provides a list of technologies, the cellulosic fuels produced and a list of many of 

the companies which we learned are pursuing the technology (or something very similar 

to the technology listed in the category). 

 

14 DOE. “Biomass Program: ABC’s of Biofuels”. Accessed at: 

http://www1.eere.energy.gov/biomass/abcs_biofuels.html#content 
DRAFT 5/18/10 

35

Table IV.C-1 

List of Technology Categories, the Fuels Produced Through Each Type of Technology, 

and the Companies Pursuing Them 

Technology 

Category 

Technology Fuels 

Produced 

Companies 

Enzymatic Hydrolysis Ethanol Abengoa, AE Fuels, 

DuPont/Danisco, Florida 

Crystals, Gevo, Poet, ICM, 

Iogen, BPI, Energy, Fiberight, 

KL Energy. 

Acid Hydrolysis Ethanol Agresti, Arkenol, Blue Fire, 

Pencor, Pangen, Raven 

Biofuels 

Dilute Acid, Steam Explosion of 

Cellulose 

Ethanol Verenium, BP, Central 

Minnesota Ethanol Coop. 

Consolidated Bioprocessing (one 

step hydrolysis and fermentation) 

of Cellulose 

Ethanol Mascoma, Qteros 

Conversion of Cellulose via 

carboxylic acid 

Ethanol, 

Gasoline, Jet 

Fuel, Diesel 

Fuel 

Terrabon, Swift Fuels 

Biochemical 

One step Conversion of Cellulose 

to distillate 

Diesel, Jet 

Fuel or 

Naphtha 

Bell Bioenergy, LS9 

Thermochemical/Fischer Tropsch Diesel Fuel 

and Naphtha 

Choren, Flambeau River 

Biofuels, Baard, Clearfuels, 

Gulf Coast Energy, Rentech, 

TRI. 

Thermochemical/Fischer Tropsch DME Chemrec, New Page. 

Thermochemical 

Thermochemical/Catalytic 

conversion of syngas to alcohols 

Ethanol Range Fuels, Pearson 

Technologies, Fulcrum 

Bioenergy, Enerkem, and Gulf 

Coast Energy. 

Thermochemical w/ Biochemical 

catalyst 

Hybrid Ethanol Coskata, INEOS Bio 

Acid Hydrolysis of cellulose to 

intermediate; hydrogenation 

using Thermochemical syngas 

from non-cellulose fraction 

Ethanol, 

Other 

alcohols 

Zeachem 

Catalytic Depolymerization of 

Cellulose 

Diesel, Jet 

Fuel or 

Naphtha 

Depolymerization Cello Energy 

Pyrolysis of Cellulose Diesel, Jet 

Fuel, or 

Gasoline 

Envergent (UOP/Ensyn), 

Dynamotive, Petrobras, Univ. 

of Mass, KIOR. 

Other Catalytic Reforming of Sugars 

from Cellulose 

Gasoline Virent 
DRAFT 5/18/10 

36

 Of the technologies listed above, many of them are considered to be “second 

generation” biofuels or new biofuel technologies capable of meeting either the advanced 

biofuel or cellulosic biofuel RFS standard. The following sections describe specific 

companies and the new biofuel technologies which the companies have developed or are 

developing. This summary is not meant to be an unabridged list of new biofuel 

technologies, but rather a description of some of the more prominent of the new biofuel 

technologies that serve to provide a sense of the technology categories listed above. The 

process technology summaries are based on information provided by the respective 

companies. EPA has not been able to confirm all of the information, statements, process 

conditions, and the process flow steps necessary for any of these processes and 

companies. 

 1. Biochemical

 Biochemical conversion refers to a broad grouping of processes that use 

biological organisms to convert cellulosic feedstocks into biofuels. While no two 

processes are identical, many of these processes follow a similar basic pathway to convert 

cellulosic materials to biofuel. The general process of most biochemical cellulosic 

biofuel processes consists of five main steps: feedstock handling, pretreatment, 

hydrolysis, fermentation/fuel conversion, and distillation/separation. The feedstock 

handling step reduces the particle size of the incoming feedstock and removes any 

contaminants that may negatively impact the rest of the process. In the pretreatment step 

the structure of the lignin and hemicellulose is disrupted, usually using some combination 

of heat, pressure, acid, or base, to allow for a more effective hydrolysis of the cellulosic 

material to simple sugars. In the hydrolysis stage the cellulose and any remaining 

hemicellulose is converted into simple sugars, usually using an enzyme or strong acid. In 

the fermentation or fuel conversion step, the simple sugars are converted to the desired 

fuel by a biological organism. In the final step the fuel that is produced is separated from 

the water and other byproducts by distillation or some other means. A basic diagram of 

the biochemical conversion process can be found in Figure IV.C.1-1 below. 
DRAFT 5/18/10 

37

Figure IV.C.1-115

While this diagram shows the production of ethanol from cellulosic biomass, it is 

possible to use the same process to produce other fuels or specialty chemicals using 

different biological organisms. 

 The following sections will discuss each of these steps in greater detail, discuss 

some of the variations to this general process, and discuss some of the advantages and 

disadvantages of the biochemical process of producing biofuel from cellulosic materials 

as compared to other fuel production processes. 

 Seven of the eight companies that EPA believes may produce cellulosic biofuel in 

2011 plan to use a biochemical process to produce biofuels. Five of these companies, AE 

Biofuels, Dupont Danisco Cellulosic Ethanol, Fiberight, Iogen, and KL energy, all plan 

to use an enzymatic hydrolysis, while Agresti Biofuels and Bell Bio-Energy are pursuing 

gravity pressure vessel and single step process technologies respectively. The main 

reason for the dominance of biochemical technologies in 2011 is the relatively low 

capital costs of these projects compared to other cellulosic biofuel facilities. Biochemical 

projects also benefit less from economies of scale, making smaller and less capital 

intensive commercial facilities more feasible. The following sections, as well as a 

technical memorandum that has been added to the docket16, provide more information on 

the biochemical processes being pursued by majority of the companies we expect to 

produce cellulosic biofuels and make them commercially available in 2011, as well as 

many other companies planning to begin production in later years. 

 a. Feedstock Handling 

 The first step of the biochemical conversion process is to insure that the biomass 

stream can be utilized by the rest of the conversion process. This most often takes the 

form of size reduction, either by grinding or chipping as appropriate for the type of 

biomass. While this is a relatively simple process it is essential to allow the following 

 

15 Image From: http://www.afdc.energy.gov/afdc/ethanol/production_cellulosic.html 

16 Wyborny, Lester. “In-Depth Assessment of Advanced Biofuels Technologies.” Memo to the docket, 

May 2010. 
DRAFT 5/18/10 

38

steps of the process to function as designed. It is also a potentially energy intensive 

process. It may be possible for biofuel producers to purchase cellulosic material that is 

already of the appropriate size, however we believe that in the near term this is unlikely 

and most biofuel producers will have to invest in equipment to reduce the size of the 

material they receive as needed for their process. In coming years, as the market for 

cellulosic materials expands, purchasing feedstock that has already been ground or 

chipped may be possible and cost effective, as these processes increase the density of this 

material and may reduce transportation costs. 

 In addition to size reduction, steps must also be taken to remove any material 

from the feedstock that might be detrimental to the fuel production process. 

Contaminants in the feedstock would at best travel through the fuel production process 

unchanged, resulting in reduced fuel production capacity. Depending on the type of 

contaminant they may also be converted to undesired byproducts that must be separated 

from the fuel. They could also be toxic to the biological organisms being used to convert 

the sugars to fuel, necessitating a shut down and restart of the plant. Any of these 

scenarios would result in a significant cost to the fuel producer. Feedstocks such as 

agricultural residues, wood chips, or herbaceous or woody energy crops are likely to 

contain far fewer contaminants than more heterogeneous feedstocks such as municipal 

solid waste (MSW). 

 b. Biomass Pretreatment 

 The purpose of the biomass pretreatment stage is to disrupt the structure of the 

cellulosic biomass to allow for the hydrolysis of the cellulose and hemicellulose into 

simple sugars. The ideal pretreatment stage would allow for a high conversion of the 

cellulose and hemicellulose to simple sugars, minimize the degradation of these sugars to 

undesired forms that reduce fuel yields and inhibit fermentation, not require especially 

large or expensive reaction vessels, and be a relatively robust and simple process. No 

single biomass pretreatment method has yet been discovered that meets all of these goals, 

but rather a variety of options are being used by various cellulosic fuel producers, each 

with their own strengths and weaknesses. Dilute acid pretreatment and alkaline 

pretreatment are two methods currently being used that attack the hemicellulose and 

lignin portions of the cellulosic biomass respectively. Other methods, such as steam 

explosion and ammonia fiber expansion, seek to use high temperature and pressure, 

followed by rapid decompression to disrupt the structure of the cellulosic biomass and 

allow for a more efficient hydrolysis of the cellulose and hemicellulose to simple sugars. 

Each of these methods is discussed in more detail in a technical memo that has been 

added to the docket17. The cost and characteristics of the cellulosic feedstock being 

processed is likely to have a significant impact on the pretreatment process that is used. 

 c. Hydrolysis 

 

17 Wyborny, Lester. “In-Depth Assessment of Advanced Biofuels Technologies.” Memo to the docket, 

May 2010. 
DRAFT 5/18/10 

39

 In the hydrolysis step the cellulose and any remaining hemicellulose are 

converted to simple sugars. There are two main methods of hydrolysis, acid hydrolysis 

and enzymatic hydrolysis. Acid hydrolysis is the oldest technology for the conversion of 

cellulosic feedstock to ethanol and can only be used following an acid pretreatment 

process. An alternative method is to use a combination of enzymes to perform the 

hydrolysis after the biomass has been pretreated. This process is potentially more 

effective at hydrolyzing pretreated biomass but in the past has not been economically 

feasible due to the prohibitively high cost of the enzymes. The falling cost of these 

enzymes in recent years has made the production of cellulosic biofuels using enzymatic 

hydrolysis possible. The lignin is largely unaffected by the hydrolysis and fuel 

production steps but is carried through these processes until it is separated out in the fuel 

separation step and burned for process energy or sold as a co-product. 

 i. Acid Hydrolysis

 Acid hydrolysis is a technique that has been used for over 100 years to convert 

cellulosic feedstocks into fuels. In the acid hydrolysis process the lignin and cellulose 

portions of the feedstock that remain after the hemicellulose has been dissolved, 

hydrolyzed, and separated during the dilute acid pretreatment process is treated with a 

second acid stream. This second acid treatment uses a less concentrated acid than the 

pretreatment stage but at a higher temperature, as high as 215° C. This treatment 

hydrolyzes the cellulose into glucose and other 6 carbon sugars that are then fed to 

biological organisms to produce the desired fuel. It is necessary to hydrolyze the 

hemicellulose and cellulose in two separate steps to prevent the conversion of the pentose 

sugars that result from the hydrolysis of the hemicellulose from being further converted 

into furfural and other chemicals. This would not only reduce the total production of 

sugars from the cellulosic feedstock, but also inhibit the production of fuel from the 

sugars in later stages of the process. 

 The acidic solution containing the sugars produced as a result of the hydrolysis 

reaction must also be treated so that this stream can be fed to the biological organisms 

that will convert these sugars into fuel. In order to operate an acid hydrolysis process 

cost effectively the acid must be recovered, not simply neutralized. Methods currently 

being used to recover this acid include membrane separation and continuous ion 

exchange. The advantages of using an acid hydrolysis are that this process is well 

understood and capable of producing high sugar yields from a wide variety of feedstocks. 

Capital costs are high however, as materials compatible with the acidic streams must be 

extensively utilized. The high temperatures necessary for acid hydrolysis also result in 

considerable energy costs, and profitability is highly dependent on the ability to 

effectively recover and reuse the acid. 

 ii. Enzymatic Hydrolysis

 The enzymatic hydrolysis process uses enzymes, rather than acids, to hydrolyze 

the cellulose and any remaining hemicellulose from the pretreatment process. This 

process is much more versatile than the acid hydrolysis and can be used in combination 
DRAFT 5/18/10 

40

with any of the pretreatment processes described above, provided that the structure of the 

lignocellulosic feedstock has been disrupted enough to allow the enzymes to easily access 

the hemicellulose and cellulose. After the feedstock has gone through pretreatment a 

cocktail of cellulose enzymes is added. These enzymes can be produced by the cellulosic 

biofuel producer or purchased from enzyme producers such as Novozymes, Genencor, 

and others. The exact mixture of enzymes used in the enzymatic hydrolysis stage can 

vary greatly depending on which of the pretreatment stages is used as well as the 

composition of the feedstock. 

 The main advantages of the enzymatic hydrolysis process are a result of the mild 

operating conditions. Because no acid is used special materials are not required for the 

reaction vessels. Enzymatic hydrolysis is carried out at relatively low temperatures, 

usually around 50° C, and atmospheric pressure and therefore has low energy 

requirements. These conditions also result in less undesired reactions that would reduce 

the production of sugars and potentially inhibit fuel production. Enzymatic hydrolysis 

works best with a uniform feedstock, such as agricultural residues or energy crops, where 

the concentration and combination of enzymes can be optimized for maximum sugar 

production. If the composition of the feedstock varies daily, as can be the case with fuel 

producers utilizing MSW or other waste streams, or even seasonally, it would make it 

more difficult to ensure that the correct enzyme cocktail is being used to carry out the 

hydrolysis as efficiently as possible. The main hurdle to using an enzymatic hydrolysis 

has been and continues to be the costs of the enzymes. Recent advances by companies 

that produce enzymes for the hydrolysis of cellulosic materials have resulted in a drastic 

cost reduction of these enzymes. If, as many researchers and cellulosic biofuel producers 

expect, the cost of these enzymes continues to fall it is likely that enzymatic hydrolysis 

will be a lower cost option than acid hydrolysis, especially for cellulosic biofuel 

producers utilizing uniform feedstocks. 

 d. Fuel Production 

 After the cellulosic biomass has been hydrolyzed to simple sugars this sugar 

solution is converted to fuel by biological organisms. In some biochemical fuel 

production processes the sugars produced from the fermentation of the hemicellulose, 

which are mainly five carbon sugars, are converted to fuel in a separate reactor and with a 

different set of organisms than the sugars produced from the cellulose hydrolysis, which 

are mainly six carbon sugars. Others processes, however, produce fuel from the five and 

six carbon sugars in the same reaction vessel. 

 A wide range of biological organisms can be used to convert the simple sugars 

into fuel. These include yeasts, bacteria, and other microbes, some of which are naturally 

occurring and others that have been genetically modified. The ideal biological organism 

converts both five and six carbon sugars to fuel with a high efficiency, is able to tolerate a 

range of conditions, and is adaptable to process sugar streams of varying compositions 

that may result from variations in feedstock. Many cellulosic biofuel producers have 

their own proprietary organism or organisms optimized to produce the desired fuel from 

their unique combination of feedstock, pretreatment and hydrolysis processes, and fuel 
DRAFT 5/18/10 

41

conversion conditions. Other cellulosic fuel producers license these organisms from 

biotechnology companies who specialize in their discovery and production. 

 The many different biological organisms being considered for cellulosic biofuel 

production are capable of producing many different types of fuels. Many cellulosic 

biofuel producers are working with organisms that produce ethanol. In many ways this is 

the most simple fuel to produce from lignocellulosic biomass as the production of ethanol 

from simple sugars is a well understood process. Others intend to produce butanol or 

other alcohols that have higher energy content. Butanol may be able to be blended into 

gasoline in greater proportion to ethanol and therefore has a potentially greater market as 

well as value due to its higher energy content. Yields for butanol, however, are currently 

significantly lower per ton of feedstock than ethanol. Some of the fuel producers who 

plan to produce alcohols are considering purchasing and modifying already existing grain 

ethanol plants. This would potentially have significant capital cost savings as many of 

the units used in a grain ethanol process are very similar to those required by the 

biochemical fuel production process and could be used with minimal modification. 

 Other cellulosic biofuel producers intend to produce hydrocarbon fuels very 

similar to gasoline, diesel, and jet fuel. These fuels command a higher price than 

alcohols, have a greater energy density, and are potentially drop in fuels that could be 

used in any conventional vehicles without strict blending limits. They could also be 

transported by existing pipelines and utilize the same infrastructure as the petroleum 

industry. Some of the processes being researched by fuel producers produce a single 

compound, such as iso-octane, that would need to be blended into petroleum gasoline in 

order to be used while others produce a range of hydrocarbons very similar to those 

found in gasoline or diesel fuel refined from petroleum and could potentially be used in 

conventional vehicles without blending. While the prospect of producing hydrocarbon 

fuels from cellulosic feedstock is promising, the current yields of fuel produced by these 

organisms are significantly lower than those that are producing ethanol and other 

alcohols. Improvement in the yields of these organisms will have to be realized in order 

for cellulosic hydrocarbon fuels produced via a biochemical process to compete with 

cellulosic ethanol, and ultimately petroleum based fuels. 

 e. Fuel Separation 

 In the fuel separation stage the fuel produced is separated from the water, lignin, 

any un-reacted hemicellulose and cellulose, and any other compounds remaining after the 

fuel production stage. The complexity of this stage is highly dependent on the type of 

fuel produced. For processes producing hydrocarbon fuels this stage can be as simple as 

a settling tank, where the hydrocarbons are allowed to float to the top and removed. 

Recovering the ethanol is a much more difficult task. To recover the ethanol a distillation 

process, nearly identical to that used in the grain ethanol industry, is used. The ethanol 

solution is first separated from the solids before being sent to a distillation column called 

a beer column. The overheads of the beer column are fed to a second distillation column, 

called a rectifier for further separation. The rectifier produces a stream with an ethanol of 

approximately 96%. A molecular sieve unit is then used to dehydrate this stream to 
DRAFT 5/18/10 

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produce fuel grade ethanol with purity greater than 99.5%. Gasoline is added to the fuel 

ethanol as a denaturant before the fuel is stored. The distillation of ethanol is a very 

energy intensive process and new technologies, such as membrane separation, are being 

developed that could potentially reduce the energy intensity, and thus the cost, of the 

ethanol dehydration process. After the fuel has been recovered the remaining lignin and 

solids are dried and either burned on site to provide process heat and electricity or sold as 

a byproduct of the fuel production process. The waste water is either recycled or sent to a 

water treatment facility. 

 f. Process Variations 

 While the process described above outlines the general biochemical process used 

by many cellulosic biofuel producers, there are several prominent variations being 

pursued by prospective biofuel producers. These variations usually seek to simplify the 

biochemical fuel production process by combining several steps into a single step or 

using other means to reduce the capital or operating costs of the process. Simultaneous 

Saccharification and Fermentation (SSF), Simultaneous Saccharification and CoFermentation (SSCF), Consolidated Bio-Processing (CBP), and Single Step Fuel 

Production are all production methods being developed by various biofuel production 

companies to combine two or more of the steps outlined above. These process variations 

are discussed in more detail in a technical memo that can be found in the docket18. These 

modifications are usually enabled by a proprietary technology or biological organism that 

makes these changes possible. 

 g. Current Status of Biochemical Conversion Technology 

 The biochemical cellulosic fuel production industry is currently transitioning from 

an industry consisting mostly of small scale research and optimization focused facilities 

to one capable of producing fuel at a commercial scale. Companies such as Iogen, 

DuPont Danisco Cellulosic Ethanol, and KL Energy are just beginning to market the fuel 

they are producing at their first small scale commercial fuel production facilities. By 

2011 we expect several other cellulosic fuel production facilities using biochemical 

processes to come online, including the first commercial scale facilities of AE Advanced 

Fuels, Agresti Biofuels, Bell Bio-Energy, and Fiberight. Many other facilities, including 

some large scale facilities capable of producing tens of millions of gallons of fuel are 

planned to come online starting in 2012 and in the following years. 

 There are many factors that are likely to continue to drive the expansion of the 

cellulosic biofuel industry. The high price of petroleum fuels and the mandates put into 

place by the RFS2 program have created a large demand for cellulosic biofuels. The 

biochemical production process also has several advantages over other methods of 

producing fuel from cellulosic feedstocks including relatively low capital costs, highly 

selective fuel production, flexibility in the type of fuel produced, and the promise of 

future production cost reductions. 

 

18 Reference docket number 
DRAFT 5/18/10 

43

 While the poor worldwide economy and tight credit markets has had a negative 

impact on the biofuel industry as a whole the cellulosic biofuel producers utilizing 

biochemical processes have not been as hard hit as many others in the industry. This is 

partially due to the relatively low capital costs of biochemical production plants as a 

result of the relative simplicity and mild operating conditions of these plants. Several 

companies have been able to purchase distressed grain ethanol plants and are in the 

process of modifying them to produce cellulosic ethanol, further reducing the capital 

costs of their initial facilities. Once biochemical fuel production facilities have been 

constructed another advantage they have over other fuel production processes is that their 

high selectivity in the fuels they produce. Unlike chemical catalysts, which often 

produce a range of products and byproducts, biological organisms often produce a single 

type of fuel, which leads to very high fuel production rates per unit sugar. Finally, there 

is a large potential to further decrease the production costs of cellulosic biofuels using the 

biochemical processes. Unlike other production methods such as gasification which are 

relatively mature technologies, biochemical production of fuels is a young technology. 

One of the major costs of the biochemical fuel production processes currently are the 

enzymes. Great strides have been made recently in reducing the cost of these enzymes, 

and as the price of enzymes continues to fall so will the operating costs of biochemical 

fuel production processes. 

 h. Major Hurdles to Commercialization 

 Despite the many promising qualities of the biochemical fuel production process 

several significant hurdles remain. Improvements must be made to the pretreatment 

processes of the cellulosic materials to maximize the conversion of cellulose and 

hemicellulose to simple sugars and to minimize the production of other undesired 

compounds, especially those that may inhibit the fuel production process. The ability of 

the biological fuel production organisms to process a wide range of both five and six 

carbon sugars must also continue to be improved. Both these improvements will increase 

the fuel yield per ton of cellulosic feedstock, reducing the operating costs of the process. 

The cost of enzymes must continue to decrease to allow the fuel produced by biochemical 

processes to be cost competitive with petroleum and other cellulosic biofuels. 

 Another significant hurdle that must be overcome is the profitable utilization of 

the lignin portion of the cellulosic feedstock. Unlike some of the other cellulosic biofuel 

production processes, the biochemical process does not convert the lignin to fuel. 

Cellulosic feedstock can contain up to 40% lignin, depending on the type of feedstock 

used, so the effective utilization of this lignin is an important piece of the profitability of 

the biochemical process. One option for the use of the lignin is to burn it to provide 

process heat and electricity, as well as excess electricity to the grid. While this would 

provide good value for the lignin, it would require fairly expensive boilers and turbines 

that increases the capital cost of the facility. If the lignin cannot be used as part of the 

fuel production process it may be able to be marketed as a solid fuel with high energy 

density and low carbon intensity. 

 2. Thermochemical 
DRAFT 5/18/10 

44

 Thermochemical conversion involves biomass being broken down into syngas 

using heat and upgraded to fuels using a combination of heat and pressure in the presence 

of catalysts.19 For generating the syngas, thermochemical processes partially oxidize 

biomass in the presence of a gasifying agent, usually air, oxygen, and/or steam. It is 

important to note that these processing steps are also applicable to other feedstocks (e.g., 

coal or natural gas); the only difference is that a renewable feedstock is used (i.e., 

biomass) to produce cellulosic biofuel. The cellulosic biofuel produced can be mixed 

alcohols, but optimizing the process to produce ethanol, or it could be diesel fuel and 

naphtha. A thermochemical unit can also complement a biochemical processing plant to 

enhance the economics of an integrated biorefinery by converting lignin-rich, nonfermentable material left over from high-starch or cellulosic feedstocks conversion.20 

Compared to corn ethanol or biochemical cellulosic ethanol plants, the use of biomass 

gasification may allow for greater flexibility to utilize different biomass feedstocks at a 

specific plant. Mixed biomass feedstocks may be used, based on availability of longterm suppliers, seasonal availability, harvest cycle, and costs. 

The general steps of the gasification thermochemical process include: feedstock 

handling, gasification, gas cleanup and conditioning, fuel synthesis, and separation. 

Refer to Figure IV.C.2-1 for a schematic of the thermochemical cellulosic ethanol 

production process through gasification. For greater detail on the thermochemical mixedalcohols route refer to NREL technical documentation.21 

 

19 US. DOE. Technologies: Processing and Conversion. Accessed at: 

http://www1.eere.energy.gov/biomass/processing_conversion.html on October 28, 2008 20 EERE, DOE, Thermochemical Conversion, & Biochemical Conversion, Biomass Program 

Thermochemical R&D . http://www1.eere.energy.gov/biomass/thermochemical_conversion.html 

http://www1.eere.energy.gov/biomass/biochemical_conversion.html 

21 Aden, Andy, Mixed Alcohols from Woody Biomass – 2010, 2015, 2022, National Renewable Energy 

Laboratory (NREL), September, 23 2009. 
DRAFT 5/18/10 

45

Figure IV.C.2-1 

 Cellulosic Ethanol Thermochemical Gasification Process 

 Figure IV.C.2-2 is a block diagram of a biomass to liquids (BTL) process which 

produces diesel fuel and naphtha through a thermochemical process. 
DRAFT 5/18/10 

46

Figure IV.C.2-2 

 Biomass to Liquids (BTL) Thermochemical Gasification Process 

 The first step in a thermochemical plant is feedstock size reduction. The particle 

size requirement for a thermochemical process is around 10-mm to 100-mm in 

diameter.22 Once the feed is ground to the proper size, flue gases from the char 

combustor and tar reformer catalyst regenerator dry the feed from the as received 

moisture level of around 30% to 50% moisture to the level required by the gasifier. 

 The dried, ground feedstock is fed to a gasification reactor for producing syngas. 

There are two general classes of gasifiers, partial oxidation (POx) and indirect gasifiers. 

Partial oxidation gasifiers (directly-heated gasifiers) use the exothermic reaction between 

oxygen and organics to provide the heat necessary to devolatilize biomass and to convert 

residual carbon-rich chars. Indirect gasifiers use steam to accomplish gasification 

through heat transfer from a hot solid or through a heat transfer surface. Either the 

byproduct char and/or a portion of the product gas can be combusted with air (external to 

the gasifier itself) to provide the energy required for gasification. The raw syngas 

produced from either type of gasifier has a low to medium energy content which consists 

mainly of CO, H2, CO2, H2O, N2, and hydrocarbons 

 Once the biomass is gasified and converted to syngas, the syngas must be cleaned 

and conditioned, as minor components of tars, sulfur, nitrogen oxides, alkali metals, and 

 

22 Lin Wei, Graduate Research Assistant, Lester O. Pordesimo, Assistant Professor 

Willam D. Batchelor, Professor, Department of Agricultural and Biological Engineering, 

Mississippi State University, MS 39762, USA, Ethanol Production from Wood: Comparison of Hydrolysis 

Fermentation and Gasification Biosynthesis, Paper Number: 076036, Written for presentation at the 2007 

ASABE Annual International Meeting. Minneapolis Convention Center, Minneapolis, MN, 17 - 20 June 

2007 
DRAFT 5/18/10 

47

particulates have the potential to negatively affect the syngas conversion steps. 

Therefore, unwanted impurities are removed in a gas cleanup step and the gas 

composition is further modified during gas conditioning. Because this step is a necessary 

part of the thermochemical process, thermochemical plants are good candidates for 

processing municipal solid waste (MSW) which may contain a significant amount of 

toxic material. Gas conditioning steps include sulfur polishing to remove trace levels of 

H2S and water-gas shift to adjust the final H2/CO ratio for optimized fuel synthesis.

 After cleanup and conditioning, the “clean” syngas is comprised of essentially CO 

and H2. The syngas is then converted into a liquid fuel by a catalytic process. The fuel 

producer has the choice of producing diesel fuel or alcohols from syngas by optimizing 

the type of catalyst used and the H2/CO ratio. Diesel fuel has historically been the 

primary focus of such processes by using a Fischer Tropsch reactor, as it produces a high 

quality distillate product. However, with a $1.01 per gallon cellulosic biofuel tax 

deduction which favors the less energy dense ethanol, it may be economically 

advantageous for fuel producers to convert syngas to ethanol instead of to diesel fuel. 

 A carefully integrated conventional steam cycle produces process heat and 

electricity (excess electricity is exported). Pre-heaters, steam generators, and superheaters generate steam that drives turbines on compressors and electrical generators. The 

heat balance around a thermochemical unit or thermochemical combined unit must be 

carefully designed and tuned in order to avoid unnecessary heat losses.23 These facilities 

greatly increase the thermal efficiency of these plants, but they add to the very high 

capital costs of these technologies. 

a. Ethanol based on a Thermochemical Platform 

Conceptual designs and techno-economic models have been developed for ethanol 

production via mixed alcohol synthesis using catalytic processes. The proposed mixed 

alcohol process produces a mixture of ethanol along with higher normal alcohols (e.g., npropanol, n-butanol, and n-pentanol). The by-product higher normal alcohols have value 

as commodity chemicals and fuel additives. 

 The liquid rundown from the low-pressure separator is dehydrated in vapor-phase 

molecular sieves, producing the dehydrated mixed alcohol feed into a methanol/ethanol 

overhead stream and a mixed, higher molecular weight alcohol bottom stream. The 

overhead stream is further separated into a methanol stream and an ethanol stream. 

 Two companies which are pursuing ethanol based on a thermochemical route are 

Range Fuels and Enerkem. Range has operated a pilot plant for over 7 years using over 

20 different nonfood feedstocks. Range broke ground building its first commercial plant 

late in late 2008 and is expected to be operational in 2010. This plant will be located in 

 

23 S. Phillips, A. Aden, J. Jechura, and D. Dayton, National Renewable Energy Laboratory, Golden, 

Colorado 80401-3393, T. Eggeman, Neoterics International, Inc., Thermochemical Ethanol via Indirect 

Gasification and Mixed Alcohol Synthesis of Lignocellulosic Biomass, Technical Report, NREL/TP-510-

41168, April 2007 
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Soperton, Georgia and is partially funded from proceeds of a DOE grant. The plant will 

use wood, grasses, and corn stover as feedstocks. In its initial phase, the Range plant is 

expected to produce 4 million gallons per year of methanol. After the company is 

confident in its operations, Range will begin efforts to expand the plant and add 

additional reaction capacity to convert the methanol to ethanol. 

Enerkem is pursuing cellulosic ethanol production via the thermochemical route. 

The Canadian-based company was recently announced as a recipient of a $50 million 

grant from DOE to build a 10 MGY woody biomass-to-ethanol plant in Pontotoc, MS. 

The U.S. plant is not scheduled to come online until 2012, but Enerkem is currently 

building a 1.3 MGY demonstration plant in Westbury, Quebec. According to the 

company, plant construction in Westbury started in October 2007 and the facility is 

currently scheduled to come online around the middle of 2010. While it’s unclear at this 

time whether the cellulosic ethanol produced will be exported to the United States, 

Enerkem has expressed interest in selling its fuel commercially. If Enerkem does export 

some of its cellulosic biofuel to the U.S., it could help to enable refiners meet the 2011 

cellulosic biofuel standard. 

 

b. Diesel and Naphtha Production based on a Thermochemical Platform 

The cleaned and water-shifted syngas is sent to the Fischer Tropsch (FT) reactor 

where the carbon monoxide and hydrogen are reacted over a FT catalyst. Current FT 

catalysts include iron-based catalysts, and cobalt-based catalysts. The FT reactor creates 

a syncrude, which is a variety of hydrocarbons that boil over a wide distillation range (a 

mix of heavy and light hydrocarbons) which are separated into various components based 

on their vapor pressure, mainly liquid petroleum gas (LPG), naphtha, distillate and wax 

fractions. The heavier compounds are hydrocracked to maximize the production of diesel 

fuel. Conversely, the naphtha material is very low in octane thus, it would either have to 

be upgraded, or blended down with high octane blendstocks (i.e., ethanol), or be 

upgraded to a higher octane blendstock to have much value for use in gasoline. 

 Choren is an European company which is pursuing a thermochemical technology 

for producing diesel fuel and naphtha. The principal aspect of Choren’s process is their 

patented three stage gasification reactor. The three-stage gasification reactor includes 

low temperature gasification, high temperature gasification and endothermic entrained 

bed gasification. Choren designed its gasification reactor with three stages to more fully 

convert the feedstock to syngas. Choren will be building a commercial Plant in Freiberg/ 

Saxony Germany that is expected to be operational in 2011 or 2012. Initially, the plant 

will use biomass from nearby forests, the wood-processing industry and straw from 

farmland. Although any fuel produced in 2011 by its Freiberg/Saxony plant and 

marketed commercially would most likely be used in Europe, it is possible that some of 

that fuel could be exported to the US. Choren is also planning to build a commercial 

thermochemical/BTL plant in the U.S. after their Freiberg/Saxony plant is operational in 

Germany. 
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Baard Energy is a U.S. company which plans on utilizing a thermochemical 

technology for producing diesel fuel and naphtha. Baard, however, plans on primarily 

combusting coal and cofiring biomass with the coal. Cofiring the biomass with the coal 

will make their first plant more like the coal-to-liquids plants which are operating today, 

which may help to convince investors that this technology is already tested. Baard’s coal 

and biomass-to-liquids plant is not expected to be operational until at least 2012. 

Probably the largest commercialization hurdle for the companies pursing the 

thermochemical route is the very high capital costs associated with these technologies. 

Because of the economic hardships associated with recent global recession, banks are less 

willing to make loans to fund new technologies which are likely to be considered riskier 

investments. The capital costs are very high because there are two significant reactors 

required for each plant – the gasification reactor and the syngas to fuel reactor. 

Additionally, the syngas must be cleaned to protect the catalysts used in the downstream 

syngas to fuel reactor which requires additional capital costs. Because the syngas would 

be cleaned anyways, this technology is a very good candidate for processing MSW which 

may contain toxic compounds. When considering the cost savings for not having to pay 

the tipping fees at municipal dumping grounds, MSW feedstocks may avoid almost all 

the purchase costs for MSW feedstocks which would significantly help offset the high 

capital costs. 

 3. Hybrid Thermochemical/Biochemical Processes

 Hybrid technologies include process elements involving both the gasification 

stage of a typical thermochemical process, as well as the fermentation stage of a typical 

biochemical process and therefore cannot be placed easily into either category. For more 

specific information regarding either biochemical processes or thermochemical, please 

see Sections IV.C.1 and IV.C.2 respectively. Currently, there are several strategies for the 

production of ethanol through hybrid processes; these strategies are differentiated by the 

order in which the thermochemical and biochemical steps take place within the process, 

as well as how the intermediate products from each step are used. 

While we do not expect significant commercial production from hybrid processes in 

2011, there are several companies pursing this approach for the future. Examples of the 

first process strategy, described in the paragraph below, include both INEOS Bio and 

Coskata. INEOS Bio (along with partner New Planet Energy) has recently been selected 

for a $50MM DOE grant for the construction of an 8 MGPY plant in River County, 

Florida; predicted to finish construction in late 2011. Coskata is currently running a 

40,000 gallon per year pilot plant that became operational in 2009 in Madison, 

Pennsylvania. Coskata is targeting to design and build a 50 MGPY commercial plant that 

it expects to be operational in 2012. A company currently pursing the second process 

strategy, described in the following third paragraph, is Zeachem Inc. Zeachem is 

currently constructing a 250 KGPY demonstration plant in Boardman, Oregon. They 

have received a $25MM DOE grant and expect to have a full commercial production 

facility operational in 2013. 
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 One strategy involves the gasification of all feedstock material to syngas before 

being processed into ethanol using a biochemical fermenter. Further information 

regarding gasification can also be found in Section IV.C.2. After gasification, the syngas 

stream is cooled and bubbled into a fermenter containing modified microorganisms, 

usually bacteria or yeast. This fermenter replaces the typical catalysts found after 

gasification in a traditional thermochemical process. Further information regarding 

fermentation can be found in Section IV.C.1. Unlike traditional fermentation (which 

break down C5 and C6 sugars), these microorganisms are engineered to convert the 

carbon monoxide and hydrogen contained in the syngas stream directly into ethanol. 

After fermentation, the effluent water/ethanol stream from the fermenter is separated 

similarly to a biochemical process; usually using a combination of distillation and 

molecular sieves. The separated water can then be recycled back into the fermentation 

stage of the process. Typical yields of ethanol are predicted in the 100 - 120 gallon per 

ton range. 

Since gasification converts all carbonaceous feedstock material to a uniform 

syngas before fermentation, there is a higher flexibility of feedstock choices than if these 

materials were to be fermented directly; including agricultural residues, switchgrass, 

farm-grown trees, sorted MSW, or any combination of such. In addition, processing 

incoming feedstock with gasification does not require the addition of enzymes or acid 

hydrolysis necessary in a biochemical process to aid in the breakdown of cellulosic 

materials. Fermenting syngas also captures all available carbon contained in the 

feedstock, including lignin that would not be processed in a typical biochemical 

fermentation. However, more energy is lost as waste heat as well as secondary carbon 

dioxide production in the gasification process than would be lost for biochemical 

feedstock preparation. Using a fermenter in a hybrid process replaces the catalyst needed 

in a typical thermochemical process. These microorganisms allow for a higher variation 

of the incoming syngas stream properties, avoid the necessity of a water-shift reaction 

preceding traditional catalytic conversion, and are able to operate at lower temperatures 

and pressures than those required for a catalytic conversion to ethanol. Microorganisms, 

unlike a catalyst, are also self-sustaining and do not require periodic replacement. They 

are; however, susceptible to bacterial and viral infections which requires periodic 

cleaning of the fermentation reactors. 

 Another hybrid production strategy involves gasification of the typically 

unfermentable feedstock fraction (lignin) concurrently with a typical fermentation step 

for the cellulose and hemicellulose fraction. These steps are subsequently combined in a 

hydrogenation reaction of the produced syngas with the product of the fermented stream. 

Feedstock first undergoes acid hydrolysis to break down contained cellulose and 

hemicellulose. Before fermentation, the unfermentable portion of feedstock (lignin, ash 

and other residue) is fractioned and sent to a gasifier. Concurrently, the remaining 

fraction of hydrolyzed feedstock is fermented using an acetogen microorganism. These 

acetogens occur naturally, and therefore do not have to be modified for this process. 

These acetogen convert both C6 and C5 portions of the hydrolized feedstock to acetic 

acid. This reaction creates no carbon dioxide, unlike traditional fermentation using yeast, 
DRAFT 5/18/10 

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preserving the maximum amount of carbon for the finished fuel. The acetic acid stream 

then undergoes esterification to create ethyl acetate. Meanwhile, the syngas stream from 

the gasification of lignin and other residue is separated into its carbon monoxide and 

hydrogen components. The carbon monoxide stream can be further combusted to provide 

process heat or energy. The hydrogen stream is combined with the ethyl acetate in a 

hydrolysis reaction to form ethanol. Acetic acid and ethyl acetate also form the precursors 

to many other chemical compounds and therefore may also be sold in addition to ethanol. 

Typical yields for this technology are predicted in the 130 – 150 gallon per ton range. 

 4. Pyrolysis and Depolymerization 

 Pyrolysis and depolymerization is a group of technologies which are capable of 

creating biofuels from cellulose by either thermally or catalytically breaking them down 

into molecules which fall within the boiling range of transportation fuels. Pyrolysis 

technologies are usually thought of being primarily a thermal technology, however, 

newer pyrolysis technologies are being developed which are attempting to integrate some 

catalysts into the technology. These are all unique processes, typically with single 

companies developing the technologies, so they are discussed separately. 

a. Pyrolysis Diesel Fuel and Gasoline 

Pyrolysis oils, or bio-oils, are produced by decomposing cellulosic biomass at 

lower temperatures than the gasification process, thus producing a liquid bio oil instead 

of a synthesis gas.24 The reaction can occur either with or without the use of catalysts, 

but it occurs without any additional oxygen being present. The resulting oil which is 

produced must have particulates and ash removed in filtration to create a homogenous 

“dirty” crude oil type of product. This dirty crude oil must be further upgraded to 

hydrocarbon fuels via hydrotreating and hydrocracking processing, which reduces its 

total oxygen content and cracks the heaviest of the hydrocarbon compounds. One of the 

finished fuels produced by the pyrolysis process is diesel fuel, however, a significant 

amount of gasoline would likely be produced as well. There are two main reaction 

pathways currently being explored: a two step pyrolysis pathway, and a one step 

pyrolysis pathway. 

The simplest technology used for the two-step pyrolysis approach is called fast 

pyrolysis. The fast pyrolysis technology uses sand in a fluidized bed to transform biofuels into a product named bio-oil. This is purely a thermal process, where the sand’s (or 

other solid) role is to transport heat to the biomass. Fast pyrolysis technology has two 

problems to be solved. First, fast pyrolysis oil is unstable, acidic, viscous and may 

separate itself into two phases so it must be immediately upgraded or it will begin to 

degrade and repolymerize. The second issue is that pyrolysis bio-oil must be upgraded 

before it can be used as a transportation fuel. 

 

24 DOE EERE Biomass Program. “Thermochemical Conversion Processes: Pyrolysis” 

http://www1.eere.energy.gov/biomass/thermochemical_processes.html, November 6, 2008. 
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Another approach to Fast Pyrolysis being pursued by several companies would be 

to substitute a catalyst in place of sand and the catalyst would be able to stabilize the 

resulting bio-oil in addition to helping depolymerize the biomass to liquids. Although the 

resulting bio-oil is stable, it still has to be upgraded into a transportation fuel, since it 

would still have a high level of oxygenated compounds. 

The National Renewable Energy Laboratory (NREL) is working on a “hot 

filtration” technology that apparently is able to stabilize bio-oil created using the fast 

pyrolysis process for a very long period of time (years). This would allow the bio-oil to 

be stored and transported to an upgrading facility without significant degradation. 

It is possible to use a sophisticated catalyst (instead of sand) in a single step 

pyrolysis reaction to create pyrolysis oils that exhibit much improved bio-oil properties. 

The catalysts would not only be able to help depolymerize cellulosic feedstocks, but they 

produce a bio-oil which could possibly be used directly as transportation fuel. Thus, a 

second upgrading step may not be necessary. The difficulty encountered by this 

technology is that catalysts which have been used in the one step process are relatively 

expensive and they degrade quickly due to the metals which are present in the biomass. 

Development work on the two-step and one-step pyrolysis processes is ongoing. 

 Dynamotive Energy Systems Corporation is a Canadian company which has 

developed a pyrolysis technology that uses medium temperatures and oxygen free 

reactions to convert dry waste biomass and energy crops into different products. The 

liquid product produced by the Dynamotive process is called BioOil. The BioOil 

contains up to 25% water, though the water is intimately mixed and does not easily 

separate into another phase with time. Since the BioOil contains significant amounts of 

water, it is not directly useable as fuel in conventional vehicles and would have to be 

converted via another catalytic conversion processing step. The additional catalytic step 

envisioned by Dynamotive to upgrade the BioOil into a transportation fuel would 

combust the material into a synthesis gas which would then be converted into diesel fuel 

or bio-methanol via a catalytic reaction (the BTL process). The diesel fuel produced is 

expected to be compatible with existing petroleum diesel fuels. The poor quality BioOil, 

though, could be used in the No. 2 industrial heating oil market at industrial facilities. 

However, because of its high acidity level, users would need to change equipment 

metallurgy to stainless steel for pipes, pumps, tanks, nozzles etc. 

 Dynamotive has two small demonstration plants. One demonstration plant is 

located in Guelph, Ontario, Canada and its capacity is 66,000 dry tons of biomass a year 

with an energy output equivalent to 130,000 barrels of oil. The other of its demonstration 

plants is located in West Lorne Ontario, Canada. Dynamotive continues to work on a 

technology for converting its BioOil to transportation fuels, although they have not 

announced plans for building such a facility due to funding limits. While Dynamotive is 

expected to continue to sell its fuel into the chemicals market, it could find a fuel oil user 

in the U.S. to use its fuel under the RFS2 program that refiners could use to comply with 

the 2011 cellulosic biofuel standard. 
DRAFT 5/18/10 

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 Envergent is a company formed through a joint venture between Honeywell’s 

UOP and the Ensyn Corporation. Although Ensyn has been using fast pyrolysis for more 

than a decade to produce specialty chemicals, UOP is relying on its decades of 

experience developing refining technologies to convert the pyrolysis oils into 

transportation fuels. Envergent is also working with Federal laboratories to further their 

technology. Based on their current technology and depending on the feedstock 

processed, about 70 % of the feedstock is converted into liquid products. The gasoline 

range products produced are high in octane, while the diesel fuel products are low in 

cetane. Envergen estimates that if it was able to procure cellulosic feedstocks at 70 per 

ton, that their technology would be competitive with #2 fuel oil produced from crude oil 

priced at about $40 per barrel. Envergent is licensing this technology as well as working 

with a U.S. oil company to test out this technology in a commercial setting here in the 

U.S. 

 Petrobras is a Brazilian oil company also working to develop a pyrolysis 

technology. Because of Petrobas’ work in this area (and other areas on biofuels), a 

Memorandum of Understanding was signed by United States‘ Secretary of State and 

Brazil’s External Relations Minister on March 9, 2007 to advance the cooperation on 

biofuels. A second Memorandum of Understanding was signed by PETROBRAS and 

NREL on September 2008 aiming at collaborating to maximize the benefit of their 

respective institutional interests in second generation biofuels. Petrobras is negotiating a 

Cooperation Agreement with NREL to develop a two step pyrolysis route to produce 

biofuels from agricultural wastes such as sugar cane bagasse, wood chips or corn stover. 

Petrobras is optimistic that a catalytic pyrolysis technology can be developed that will 

produce a stable bio-oil (pyrolysis oil). Petrobras is hopeful that a one-step pyrolysis 

technology can be developed to convert biomass directly to transportation fuels, although 

in the end Petrobras believes that the two step process may be more economically 

attractive. 

b. Catalytic Depolymerization 

 Two companies that are pursuing catalytic depolymerization are Green Power Inc. 

and Cello Energy. 

 The Green Power process catalytically depolymerizes cellulosic feedstocks at 

moderate temperatures into liquid hydrocarbon fuels. The proposed feedstock is 

municipal solid waste (MSW) or other waste material such as animal waste, plastics, 

agriculture residue, woody biomass and sewage waste. The feedstock is first ground to a 

size finer than 5 mm. The feedstock is placed along with a catalyst, some lime, which 

serves as a neutralizing agent, and some fuel which provides a liquid medium, into a 

reactor and heated to around 350 degrees Celsius. As described, this technology may fit 

the description for catalyzed pyrolysis reactions described above, but because we are not 

certain of the reaction kinetics, we have categorized this as a separate catalytic 

depolymerization technology. In the reactor, the feedstock is catalytically converted to 

liquid fuels which primarily fall within the gasoline and diesel fuel boiling ranges, 

although these fuels may need further upgrading. The liquid fuels are separated from 
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some solids which are present and are distilled into typical fuel streams including 

naphtha, diesel fuel, kerosene and fuel oil. According to the literature writing about this 

technology, the process reportedly produces 120 gallons per ton of feedstock inputted 

into the process. A light hydrocarbon gas, which is mostly methane, is also produced, but 

this gas is expected to be burned in a turbine to generate electricity and the waste heat is 

used for heating the process. Apparently, some carbon dioxide is also formed and is 

released from the process. 

 Greenpower completed construction on a demonstration plant located in Fife, 

Washington about March of 2008. Greenpower is working on obtaining additional 

funding and to obtain an air permit through the State of Washington Environmental 

Office. While we don’t believe that Greenpower will have its plant operational in 2011 

due to financial and other issues the company faces, those issues could be resolved to 

allow this company to produce fuel that could help refiners comply with the cellulosic 

biofuel volume standard for 2011. 

 The Cello-Energy process is also a catalytic depolymerization technology. At 

moderate pressure and temperature, the Cello-Energy process catalytically removes the 

oxygen and minerals from the hydrocarbons that comprise finely ground cellulose. This 

results in a mixture of short chain (3, 6 and 9 carbon) hydrocarbon compounds. These 

short chain hydrocarbon compounds are polymerized to form compounds that boil in the 

diesel boiling range, though the process can also be adjusted to produce gasoline or jet 

fuel. The resulting diesel fuel meets the ASTM standards, is in the range of 50 cetane to 

55 cetane and typically contains 3 ppm of sulfur. 

 The Cello process is reported to be on the order of 82 % efficient at converting the 

feedstock energy content into the energy content of the product, which is very high 

compared to most of today's biochemical and thermochemical processes which are on the 

order of 50 % efficient, or less. Because of the simplicity of the process, the capital costs 

are very low. A 50 million gallon per year plant is claimed to only incur a total cost of 

$45 million. Because of its high efficiency in converting feedstocks into liquid fuel, the 

production and operating costs are estimated to be very low. 

 In December 2008, Cello completed construction on a 20 million gallon per year 

commercial demonstration plant. However, at the present they are still working to 

resolve process issues that have arisen upon scaleup from their pilot plant. We expect 

that Cello will be able to produce some volume of cellulosic biofuel in 2011. 

 

5. Catalytic Reforming of Sugars to Gasoline

 Virent Biorefining is pursuing a process called “Bioforming” which functions 

similarly as the gasoline reforming process used in the refining industry. Hence, this is a 

very different technology to any of those other cellulosic biofuel technologies discussed 

above. While refinery-based catalytic reforming technologies raise natural gasoline’s 

octane value and produces aromatic compounds, Bioforming reforms biomass-derived 
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sugars into hydrocarbons for blending into gasoline and diesel fuel. The process operates 

at moderate temperatures and pressures. In March of 2010, Virent announced that they 

had begun operating a larger pilot plant capable of about 30 gallons per day. 

Commercialization of the Virent process will happen sometime after 2011. 

 For this technology to become a cellulosic biofuel technology, it will be necessary 

to link this reforming technology with a technology which breaks cellulose down into 

starch or sugars. In parallel with its Bioreforming work, Virent is working on a 

technology to break down cellulose into sugars upstream of its technology which reforms 

sugars to gasoline. 
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V. Proposed Changes to RFS2 Regulations 

 Following publication of the final RFS2 program regulations25, EPA identified 

two program areas that could benefit from the addition of new regulatory provisions. The 

first would provide for the generation of RINs for fuel produced between July 1, 2010 

and December 31, 2010 representing certain fuel pathways that are not currently in Table 

1 to §80.1426, but which could possibly be added later this year if they are determined to 

meet the applicable GHG thresholds. Under this proposal RINs could be generated only 

if the pathways are indeed approved, and only for quantities reflecting fuel produced 

between the effective date of the RFS2 regulations and the effective date of a new 

pathway added to Table 1 to §80.1426. The second program addition would establish 

procedures for petitions requesting EPA authorization of an aggregate compliance 

approach to renewable biomass verification for feedstocks grown in foreign countries, 

akin to that applicable to crops and crop residue grown within the U.S. We are proposing 

to make amendments to the RFS regulations in Subpart M to implement both of these 

provisions. 

A. Delayed RIN Generation for New Pathways 

 As described in the RFS2 final rule, we did not have sufficient time to complete 

the necessary lifecycle GHG impact assessment for certain fuel pathways. We indicated 

that we would model and evaluate several additional pathways after the final rule (see 

Section V.C of the RFS2 final rule, 75 FR 14796). EPA anticipates modeling and 

publishing the lifecycle GHG analyses for the following four pathways later this year: 

 • Grain sorghum ethanol 

 • Pulpwood biofuel 

 • Palm oil biodiesel 

 • Canola oil biodiesel 

Depending on how these lifecycle GHG results compare with the required GHG 

thresholds for cellulosic biofuel, biomass-based diesel, advanced biofuel, and 

conventional renewable fuel, we may add one or more of these pathways to Table 1 to 

§80.1426. Once a new pathway is approved, producers using that pathway could 

generate RINs with the specified D code. 

 We consider the four new fuel pathways currently being analyzed to be an 

extension of the RFS2 final rule. Had we been able to complete these analyses for the 

RFS2 final rule and verified that the GHG thresholds had been met, D codes to represent 

these pathways would have been included in Table 1 to §80.1426 promulgated on March 

26, 2010, and renewable fuel producers could have begun using those pathways to 

generate RINs beginning on July 1, 2010. Indeed, we are aware of a number of 

producers who intend to produce biofuel using one of the four pathways listed above 

 

25 75 FR 14670, March 26, 2010 
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despite the fact that a determination regarding their lifecycle GHG impact has not yet 

been made. 

 Based on the fact that we may have included the four pathways listed above in the 

RFS2 final rule if the lifecycle modeling had been completed in time, we believe that it 

would be appropriate to allow renewable fuel producers using any of these four pathways 

that are ultimately approved for inclusion in Table 1 to §80.1426 to generate RINs for all 

fuel they produce and sell on and after July 1, 2010. However, while EPA is 

expeditiously working to complete its GHG assessments for these four fuel pathways in 

2010, the determination of whether any of the four pathways will meet the 20%, 50%, or 

60% GHG thresholds may not occur until after July 1, 2010. Therefore, RINs 

representing fuel produced between July 1, 2010 and any EPA approval of a new fuel 

pathway could only be generated after the renewable fuel in question had been produced 

and sold, after the time when EPA announces the results of the lifecycle analyses and 

specifies the applicable D code in Table 1 to §80.1426. Thus we are proposing a new 

regulatory provision for the generation of “Delayed RINs” that would allow RINs with 

newly specified D codes to be generated for eligible fuel produced between July 1, 2010 

and the date any new D code is approved for one of the four fuel pathways listed above. 

This Delayed RINs provision would only be applicable for any of the four pathways 

described above that are determined to meet the applicable GHG thresholds. We are also 

proposing that this provision would apply only for renewable fuel produced in 2010, 

since the lifecycle GHG assessments for the four pathways listed above is expected to be 

completed in 2010. Our proposed regulatory provision for Delayed RIN generation 

would be inserted into §80.1426 as new paragraph (g). As for any RIN generation, 

producers using this new regulatory provision would need to be registered under RFS2 

before they could generate Delayed RINs, and would need to comply with the 

recordkeeping and reporting requirements of the regulations. 

 We do not believe that this proposed provision for Delayed RINs should be 

extended to any other pathways. The four pathways listed above are the only pathways 

currently under evaluation that would have been included in the RFS2 final rule if we had 

completed the modeling in time. Moreover, we have provided a petition process in 

§80.1416 for other fuel pathways for which lifecycle GHG assessments have not yet been 

made. 

 In developing this proposed provision for Delayed RIN Generation, we have 

accounted for renewable fuel producers who are eligible for an exemption from the 20% 

GHG reduction requirement for their fuel under §80.1403 (“grandfathered” producers) 

and those that are not. Grandfathered producers can generate RINs for their renewable 

fuel starting on July 1, 2010, but must designate the D code as 6 for such fuel, identifying 

it as conventional renewable fuel. They must also transfer those RINs with renewable 

fuel they sell. If one of the four fuel pathways described above is approved between July 

1, 2010 and December 31, 2010 for use of a D code other than 6, and the producer wishes 

to apply this new D code to fuel they have already produced and transferred, the RINs 

they already generated and transferred with renewable fuel they produced must be 

accounted for. We are proposing a process whereby these grandfathered producers 
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would be required to acquire and retire RINs from the open market with a D code of 6 

prior to the generation of Delayed RINs. The number of RINs retired in this fashion must 

be no greater than the number they generated between July 1, 2010 and the effective date 

of the new applicable pathway. Producers who are not grandfathered under §80.1403 

cannot generate RINs starting on July 1, 2010, and so would not be required to acquire 

and retire any RINs prior to the generation of Delayed RINs. 

 The generation of Delayed RINs would also differ for grandfathered producers 

and non-grandfathered producers. Grandfathered producers would base the number of 

Delayed RINs they generate on the number of RINs with a D code of 6 that they retired 

as described above. In contrast, non-grandfathered producers would base the number of 

Delayed RINs they generate on the volume of renewable fuel they produced and sold 

between July 1, 2010 and the effective date of the new pathway. Since all Delayed RINs 

will be generated after the renewable fuel in question had been produced and sold, they 

would be assigned a K code of 2 and thus could be sold by the producer separately from 

renewable fuel. 

 Finally, we believe that there should be a deadline for the generation of Delayed 

RINs to ensure that they are entering the market as close as possible to the date of 

production of the renewable fuel that they represent. We are proposing that all Delayed 

RINs must be generated within 30 days of the effective date of a new pathway added to 

Table 1 to §80.1426 between July 1, 2010 and December 31, 2010. We believe that 30 

days would provide sufficient time for producers who are grandfathered to first acquire 

and retire RINs from the open market, and would be sufficient to allow any producer to 

generate Delayed RINs according to the procedures in the regulations. However, we 

request comment on a longer period within which Delayed RINs must be generated. 

 We request comment on our proposed provision for Delayed RINs. 

B. Criteria and Process for Adoption of Aggregate Approach to 

Renewable Biomass for Foreign Countries

In the preamble to the final RFS2 regulations, EPA indicated that, while we did 

not have sufficient data at the time to make a finding that the aggregate compliance 

approach adopted for domestically-grown crops and crop residues would be appropriate 

for foreign-grown feedstocks, we would consider applying the aggregate compliance 

approach for renewable biomass on a country by country basis if adequate land use data 

becomes available. 

Since promulgation of the final RFS2 regulations, we have received several 

inquiries regarding the process, criteria, and data needed for EPA to approve the 

aggregate compliance approach for planted crops and crop residue grown in areas outside 

the U.S. Thus, in today’s rule, EPA is proposing a process by which entities may petition 

EPA for approval of the aggregate compliance approach for specified renewable fuel 

feedstocks either in a foreign country as a whole or in a specified geographical area. The 
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proposed regulations include a general criterion and a number of considerations that EPA 

will use in evaluating petitions. They also include a list of submissions that are required, 

absent an explanation by petitioner of why they should not be required for EPA to 

approve a petition. The proposed rule also includes a description of the proposed process 

by which EPA would make decisions concerning any petitions received. 

1. Criterion and Considerations

In developing these proposed regulations, EPA relied substantially on the 

approach we used to determine that an aggregate compliance approach was appropriate 

for planted crops and crop residue from U.S. agricultural land. The fundamental finding 

that would be required of EPA in approving a petition for application of the aggregate 

approach would be that an aggregate compliance approach will provide reasonable 

assurance that specified renewable fuel feedstocks from a given geographical area meet 

the definition of renewable biomass and will continue to meet the definition of renewable 

biomass, based on the submission of credible, reliable and verifiable data. Based on our 

experience in making the comparable finding for U.S.-grown crops and crop residues, we 

are also proposing a number of more specific factors that would be considered in 

determining whether this finding should be made, as described below. EPA is proposing 

to consider: 

• Whether there has been a reasonable identification of the aggregate 

amount of agricultural land in the specified geographical area on 

December 19, 2007 that was available for the production of the specified 

feedstock(s) and that satisfy the definition of renewable biomass, taking 

into account the definitions of terms such as “cropland,” “pastureland,” 

“planted crop,” and “crop residue” included in the final RFS2 regulations. 

• Whether information from years preceding and following 2007 shows that 

the identified aggregate amount of land in the specific geographical area, 

called the 2007 baseline area of land, is not likely to be exceeded in the 

future. 

• Whether economic considerations, legal constraints, historical land use 

and agricultural practices and other factors show that it is likely that 

producers of the feedstock(s) will continue to use agricultural land within 

the baseline area of land identified into the future, as opposed to clearing 

and cultivating land not eligible under the 2007 baseline. 

• Whether there is a reliable method to evaluate on a continuing basis 

whether the 2007 baseline area of land is being or has been exceeded. 

• Whether an entity has been identified to conduct data gathering and 

analysis needed for an annual EPA evaluation of the aggregate compliance 

approach if EPA grants the petition. 

EPA is requesting comments on the proposed general criterion and specific 

considerations for approving the aggregate compliance approach for non-domestically 

grown feedstocks. The existing approved aggregate approach for US domestic 

feedstocks applies to all crops and crop residue that could be used in renewable fuel 
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production. EPA has received inquiries on the extent to which approval could be 

obtained for a single, or limited number, of feedstocks. The proposed regulations leave 

open the possibility of feedstock-specific petitions, but EPA particularly solicits comment 

on the extent to which different or additional data submittals or inquiries would be 

appropriate for such petitions. 

 

 2. Data Sources

To make the aggregate compliance determination for U.S. agricultural lands, EPA 

obtained USDA data from three independently gathered national land use data sources 

(the Farm Service Agency (FSA) Crop History Data, the USDA Census of Agriculture 

(2007), and the satellite-based USDA Crop Data Layer (CDL)). Please see Section 

II.C.4.c.iii.of the preamble to the final RFS2 rule (75 Fed. Reg. 14701 (March 26, 2010)) 

for a more detailed description of the data sources used. Using these data sources, EPA 

was able assess the area of land (acreage) available in the United States under EISA for 

production of crops and crop residues that meet the definition of renewable biomass. In 

the case of a petition to apply the aggregate compliance approach to feedstocks from a 

specific geographical area in a foreign country, when considering the information and 

data submitted by the petitioner, EPA will evaluate such information on a case-by-case 

basis, but suggests that petitioners obtain data from sources that are at least as credible, 

reliable, and verifiable as the USDA data used to make the determination for U.S. 

agricultural land. 

When evaluating whether the data relied on are credible, reliable, and verifiable, 

EPA will take into account whether the data is submitted by, generated by, or approved 

by the national government of the foreign country in question, as well as how 

comprehensive and accurate the data source is. It is important for the national 

government of the area seeking consideration be involved in this process, and we seek 

comment on whether or not involvement of the national government should be required 

as part of the petitioning and/or data submittal processes. Additionally, EPA will take 

into consideration whether the data is publically available, whether the data collection 

and analysis methodologies and information on the primary data source are available to 

EPA, and whether the data has been generated, analyzed, and/or approved or endorsed by 

an independent third party. EPA would also take into account the quality of the data that 

is available on an annual basis for EPA’s annual assessments of any approved aggregate 

compliance approach, as well as whether the petitioner has identified an entity who will 

provide to EPA an analysis of the data updates each year following EPA’s approval of 

the aggregate compliance approach for that area. Furthermore, EPA will consider 

agricultural land use trends from several years preceding 2007, as well as the years 

following 2007 to the time the petition is submitted in order to evaluate whether or not it 

is likely that a 2007 baseline would be exceeded in the future. EPA will consider 

whether there are laws in place in the area for which the petition was submitted that 

might prohibit or incentivize the clearing of new agricultural lands and the efficacy of 

these laws. EPA will also assess whether any market factors are expected to drive an 

increase in the demand for agricultural land. 
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3. Petition Submission 

EPA is proposing that all submittals, including the petition, supporting 

documentation, and annual data and analyses, be submitted in English. We are also 

proposing that petitioners submit specified information as part of their formal petition 

submission package, or explain why such information is not necessary for EPA to 

approve their petition. Petitioners would need to submit an assessment of the total 

amount of land that is cropland or pastureland that was cleared or cultivated prior to 

December 19, 2007 and that was actively managed or fallow and nonforested on that 

date. For example, in assessing the amount of total existing agricultural land in the U.S. 

on the enactment date of EISA, EPA used FSA Crop History data to show that there were 

402 million acres of agricultural land existing in the U.S. in 2007. Additionally, if the 

petitioner is seeking approval of the aggregate compliance approach for a particular 

feedstock, they would also need to submit an assessment of the total amount of 

agricultural land dedicated to that feedstock in 2007 within the specified area. 

Petitioners would also be required to provide EPA with maps or electronic data 

identifying the boundaries of the land in question and a description of the feedstock(s) for 

which the petitioner is submitting the petition. 

As part of the petition, the petitioner would be required to submit to EPA land use 

data that demonstrates that the land in question is agricultural land that was cleared or 

cultivated prior to December 19, 2007 and that was actively managed or fallow and 

nonforested on that date, which may include satellite imagery data, aerial photography, 

census data, agricultural surveys, and/or agricultural economic modeling data. As 

mentioned above, the FSA crop history data used for the U.S. aggregate compliance 

approach determination consists of annual records of farm-level land use data that 

includes all cropland and pastureland in the U.S. EPA also considered USDA Census of 

Agriculture data, which consists of a full census of the U.S. agricultural sector once every 

five years, as well as the USDA Nation Agricultural Statistics Service (NASS) Crop Data 

Layer (CDL), which is based on satellite data. 

 In establishing the total amount of existing agricultural land for the U.S. 

aggregate compliance approach determination, EPA relied on the RFS2 definitions of the 

relevant terms, including planted crops, crop residue, and agricultural land, which is 

defined as consisting of cropland, pastureland and CRP land. EPA will take into 

consideration whether the data submitted by the petitioner relies on comparable 

definitions. For purposes of RFS2, planted crops are defined as all annual or perennial 

agricultural crops from existing agricultural land that may be used as feedstocks for 

renewable fuel, such as grains, oilseeds, sugarcane, switchgrass, prairie grass, duckweed, 

and other species (but not including algae species or planted trees), providing they were 

intentionally applied by humans to the ground, a growth medium, a pond or tank, either 

by direct application as seed or plant, or through intentional natural seeding or vegetative 

propagation by mature plants introduced or left undisturbed for that purpose. Crop 

residue is defined as the biomass left over from the harvesting or processing of planted 

crops from existing agricultural land and any biomass removed from existing agricultural 

land that facilitates crop management (including biomass removed from such lands in 
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relation to invasive species control or fire management), whether or not the biomass 

includes any portion of a crop or crop plant. Cropland is defined as land used for 

production of crops for harvest and includes cultivated cropland, such as for row crops or 

close-grown crops, and non-cultivated cropland, such as for horticultural or aquatic crops. 

Pastureland is land managed for the production of indigenous or introduced forage plants 

for livestock grazing or hay production, and to prevent succession to other plant types. It 

is important to note that EPA considers pastureland to be distinctly different from 

rangeland, which may be used for livestock grazing, but is not managed to prevent 

succession to other plant types. Finally, CRP land is land enrolled in the US 

Conservation Reserve Program (administered by USDA’s Farm Service Agency), which 

encourages farmers to convert highly erodible cropland or other environmentally 

sensitive acreage to vegetative cover, such as tame or native grasses, wildlife plantings, 

trees, filterstrips, or riparian buffers. EPA recognizes that the CRP is only applicable to 

U.S. agricultural land. EPA solicits comments on whether the final rules should allow 

EPA to consider land that is equivalent or similar to US CRP land as existing agricultural 

land for purposes of RFS2-compliant feedstock cultivation in a foreign county, and 

whether EPA should be able to make such a determination in the context of a petition for 

application of the aggregate approach to a foreign country. 

The petitioner would also be required to provide EPA with historical land use data 

for the land in question, covering the years from prior to 2007 to the current year. For the 

U.S. aggregate compliance approach determination, EPA analyzed the FSA Crop History 

data from the years 2005 through 2007 and the USDA Census of Agriculture from 1997 

through 2007, finding that there was an overall decade trend of contraction of agricultural 

land utilization in the U.S. The petitioner would need to provide a description of any 

applicable laws, agricultural practices, economic considerations, or other relevant factors 

that had or may have an effect on the use of the land in question. For the U.S. aggregate 

compliance approach determination, EPA also took in account the EISA renewable fuel 

obligations, the unsuitability and high cost of developing previously undeveloped land for 

agricultural purposes, as well as projected increases in crop yields on existing agricultural 

land. 

Finally, the petitioner would be required to provide EPA with a plan describing 

how the entity who will, on a continuing yearly basis, conduct any data gathering and 

analysis necessary to assist EPA in its annual assessment of any approved aggregate 

approach. In the plan, the petitioner would describe the data, the data source, and the 

schedule on which the data would be updated and made available to EPA and the public. 

Additionally, the plan would include the entity’s strategy and schedule for conducting an 

annual analysis of the data and providing it to EPA. 

4. Petition Process

We believe that it will be important to incorporate a public comment component 

into EPA’s deliberations on a petition made to incorporate an aggregate compliance 

approach for a new area. EPA plans to publish a Federal Register notice informing the 

public of incoming petitions, with information on how to view the petitions and any 
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supporting information. EPA proposes to then accept public comment on the petition for 

a specified period of time. Once the public comment period closes, EPA will make an 

assessment, taking into account the information submitted in the petition as well as the 

comments received, and will then publish a decision in the Federal Register to either 

approve or deny the petitioner’s request. If the petition has been approved, the Federal 

Register notice will specify an effective date at which time producers using the specified 

feedstocks from the specified areas identified in EPA’s approval will be subject to the 

aggregate compliance approach requirements in 40 CFR 80.1454(g) in lieu of the 

renewable biomass recordkeeping and reporting requirements. In the event that the 

annual data submitted by the petitioner is insufficient to demonstrate that the baseline 

amount of land has not been exceeded or if the annual data is not submitted in a timely 

manner, EPA will make a finding that the baseline acreage has been exceeded and 

producers using crops or crop residue from the specified area will be subject to the 

individual recordkeeping and reporting requirements described in the regulations. EPA is 

seeking comments on this proposed process. 
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VI. Public Participation 

 We request comment on all aspects of this proposal. This section describes how 

you can participate in this process. 

A. How Do I Submit Comments? 

We are opening a formal comment period by publishing this document. We will 

accept comments during the period indicated under DATES in the first part of this 

proposal. If you have an interest in the proposed standards and changes to the RFS 

regulations described in this document, we encourage you to comment on any aspect of 

this rulemaking. We also request comment on specific topics identified throughout this 

proposal. 

Your comments will be most useful if you include appropriate and detailed 

supporting rationale, data, and analysis. Commenters are especially encouraged to 

provide specific suggestions for any changes that they believe need to be made. You 

should send all comments, except those containing proprietary information, to our Air 

Docket (see ADDRESSES in the first part of this proposal) before the end of the 

comment period. 

 You may submit comments electronically, by mail, or through hand 

delivery/courier. To ensure proper receipt by EPA, identify the appropriate docket 

identification number in the subject line on the first page of your comment. Please ensure 

that your comments are submitted within the specified comment period. Comments 

received after the close of the comment period will be marked “late.” EPA is not 

required to consider these late comments. If you wish to submit Confidential Business 

Information (CBI) or information that is otherwise protected by statute, please follow the 

instructions in Section VI.B. 

B. How Should I Submit CBI to the Agency? 

Do not submit information that you consider to be CBI electronically through the 

electronic public docket, www.regulations.gov, or by e-mail. Send or deliver information 

identified as CBI only to the following address: U.S. Environmental Protection Agency, 

Assessment and Standards Division, 2000 Traverwood Drive, Ann Arbor, MI, 48105, 

Attention Docket ID EPA-HQ-OAR-2010-0133. You may claim information that you 

submit to EPA as CBI by marking any part or all of that information as CBI (if you 

submit CBI on disk or CD ROM, 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 

CBI). Information so marked will not be disclosed except in accordance with procedures 

set forth in 40 CFR part 2. 
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In addition to one complete version of the comments that include any information 

claimed as CBI, a copy of the comments that does not contain the information claimed as 

CBI must be submitted for inclusion in the public docket. If you submit the copy that 

does not contain CBI on disk or CD ROM, mark the outside of the disk or CD ROM 

clearly that it does not contain CBI. Information not marked as CBI will be included in 

the public docket without prior notice. If you have any questions about CBI or the 

procedures for claiming CBI, please consult the person identified in the FOR 

FURTHER INFORMATION CONTACT section. 
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VII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory Planning and Review 

 

 Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993), this action is 

a "significant regulatory action” because it raises novel legal or policy issues. 

Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) 

for review under EO 12866 and any changes made in response to OMB recommendations 

have been documented in the docket for this action. 

 The economic impacts of the RFS2 program on regulated parties, including the 

impacts of the required volumes of renewable fuel, were already addressed in the RFS2 

final rule promulgated on March 26, 2010 (75 FR 14670). This action proposes the 

percentage standards applicable in 2011 based on the volumes that were analyzed in the 

RFS2 final rule. This action also proposes two new regulatory provisions that have been 

determined to have no adverse economic impact on regulated parties since they would 

increase flexibility to produce qualifying renewable fuel under the RFS2 program. 

B. Paperwork Reduction Act 

 This action does not impose any new information collection burdens, as we have 

determined that this rule does not impose any additional reporting requirements on 

regulated parties beyond those already required under RFS2. Therefore, there will not be 

any additional reporting burdens on entities impacted by this rulemaking. This action 

makes adjustments to the renewable fuel volume requirements specified in RFS2, as well 

as creating a temporary and limited means for certain renewable fuel producers to 

generate RINs after they have produced and sold fuel. The action also establishes criteria 

for foreign countries to adopt an aggregate approach to compliance with the renewable 

biomass provision akin to that applicable to the U.S. 

The Office of Management and Budget (OMB) has previously approved the 

information collection requirements contained in the existing RFS2 regulations 75 FR 

14670, March 26, 2010 under the provisions of the Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. and has assigned OMB control number 2060-0637. These preapproved 

items include registration (general and Central Data Exchange), independent third party 

engineering reviews, petitions for new renewable fuels and pathways, and additional 

items of reporting for foreign RIN owners. These preapproved items take effect before 

July 1, 2010. Additional information collection requirements related to RFS2 are 

currently under review at OMB. The OMB control numbers for EPA's regulations in 40 

CFR are listed in 40 CFR part 9. 

C. Regulatory Flexibility Act 
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 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-forprofit enterprise which is independently owned and operated and is not dominant in its 

field. 

 After considering the economic impacts of today’s proposed rule on small entities, 

we certify that this proposed action will not have a significant economic impact on a 

substantial number of small entities. This rule sets the annual standard for cellulosic 

biofuels, proposes a regulatory provision for the generation of Delayed RINs, and 

establishes criteria for foreign countries to adopt an aggregate approach of compliance 

with the renewable biomass provision similar to that used in the U.S. However, the 

impacts of the RFS2 program on small entities were already addressed in the RFS2 final 

rule promulgated on March 26, 2010 (75 FR 14670). Therefore, this proposed rule will 

not impose any additional requirements on small entities. We continue to be interested in 

the potential impacts of the proposed rule on small entities and welcome comments on 

issues related to such impacts. 

 

 D. Unfunded Mandates Reform Act 

 This action contains no Federal mandates under the provisions of Title II of the 

Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531-1538 for State, local, 

or tribal governments or the private sector. The action imposes no enforceable duty on 

any State, local or tribal governments or the private sector. Therefore, this action is not 

subject to the requirements of sections 202 or 205 of the UMRA. 

This action 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. 

 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 
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government, as specified in Executive Order 13132. This proposed rule 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. Thus, Executive Order 13132 does not apply to this rule. 

 In the spirit of Executive Order 13132, and consistent with EPA policy to promote 

communications between EPA and State and local governments, EPA specifically solicits 

comment on this proposed rule from State and local officials. 

F. Executive Order 13175: Consultation and Coordination with Indian 

Tribal Governments 

 This action does not have tribal implications, as specified in Executive Order 

13175 (65 FR 67249, November 9, 2000). This proposed rule does not have tribal 

implications, as this rule will be implemented at the Federal level and impose compliance 

costs only on transportation fuel refiners, blenders, marketers, distributors, importers, and 

exporters. Tribal governments would be affected only to the extent they purchase and 

use regulated fuels. 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 and because it implements specific standards established 

by Congress in statutes. 

H. Executive Order 13211: Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use 

 This rule is not a “significant energy action” as defined in Executive Order 13211, 

“Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, 

or Use” (66 FR 28355 (May 22, 2001)) because it is not likely to have a significant 

adverse effect on the supply, distribution, or use of energy. 

I. National Technology Transfer Advancement Act 

 Section 12(d) of the National Technology Transfer and Advancement Act of 1995 

(“NTTAA”), Public Law No. 104-113, 12(d) (15 U.S.C. 272 note) directs EPA to use 
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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 proposed rulemaking does not involve technical standards. Therefore, EPA is 

not considering 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 proposed 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. This action does not relax the control measures on sources regulated by 

the RFS2 regulations and therefore will not cause emissions increases from these sources. 
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VIII. Statutory Authority 

Statutory authority for this action comes from section 211 of the Clean Air Act, 

42 U.S.C. 7545. Additional support for the procedural and compliance related aspects of 

today's proposal, including the proposed recordkeeping requirements, come from 

Sections 114, 208, and 301(a) of the Clean Air Act, 42 U.S.C. Sections 7414, 7542, and 

7601(a). 

 

List of Subjects in 40 CFR Part 80 

Environmental protection, Air pollution control, Diesel Fuel, Fuel additives, Gasoline, 

Imports, Labeling, Motor vehicle pollution, Penalties, Reporting and recordkeeping 

requirements. 

Dated: 

Lisa P. Jackson, 

Administrator. 
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For the reasons set forth in the preamble, 40 CFR part 80 is proposed to be 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, 7542, 7545, and 7601(a). 

2. Section 80.1426 is amended by revising paragraph (e)(1) and adding paragraph 

(g) to read as follows: 

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

renewable fuel producers or importers? 

* * * * * 

(e) * * * 

(1) Except as provided in paragraph (g)(8) of this section for delayed RINs, 

the producer or importer of renewable fuel must assign all RINs generated 

to volumes of renewable fuel. 

* * * * * 

(g) Delayed RIN generation. Parties who produce or import renewable fuel may 

generate delayed RINs to represent renewable fuel volumes that have already 

been transferred to another party if those renewable fuel volumes can be described 

by a pathway that has been added to Table 1 to §80.1426 on or after July 1, 2010 

and before January 1, 2011. 

(1) When a new pathway is added to Table 1 to §80.1426, EPA will specify 

the effective date of that new pathway. This date will generally be the 

effective date of the rule in which the pathway is added. 

(2) Delayed RINs must be generated within 30 days of the date specified in 

paragraph (g)(1) of this section. 

(3) Delayed RINs may only be generated to represent renewable fuel 

produced or imported between July 1, 2010 and the date specified in 

paragraph (g)(1) of this section. 

(4) If a party originally generated and transferred RINs with renewable fuel 

volumes, and those RINs can be described by a pathway added to Table 1 

to §80.1426 on or after July 1, 2010 and before January 1, 2011, that party 

must retire a number of gallon-RINs prior to generating delayed RINs. 
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(i) The number of gallon-RINs retired must not exceed the number of 

gallon-RINs originally generated to represent the renewable fuel 

volumes produced or imported between July 1, 2010 and the date 

specified in paragraph (g)(1) of this section. 

(ii) Retired RINs must have a D code of 6. 

(iii) Retired RINs must have a K code of 2. 

(iv) Retired RINs must have been generated in 2010. 

(5) For parties that retire RINs pursuant to paragraph (g)(4) of this section, the 

number of delayed gallon-RINs generated shall be equal to the number of 

gallon-RINs retired. 

(6) For parties that did not retire RINs pursuant to paragraph (g)(4) of this 

section, the number of delayed gallon-RINs generated shall be determined 

pursuant to paragraph (f) of this section. 

(i) The standardized volume of fuel (Vs) used to determine the RIN 

volume (VRIN) under paragraph (f) of this section shall be the 

standardized volume of renewable fuel produced or imported 

between July 1, 2010 and the date specified in paragraph (g)(1) of 

this section. 

(ii) The renewable fuel for which delayed RINs are generated must be 

described by a pathway that has been added to Table 1 to §80.1426 

on or after July 1, 2010 and before January 1, 2011. 

(7) All delayed RINs generated by a renewable fuel producer must be 

generated on the same date. 

(8) Delayed RINs shall have a K code of 2. 

(9) The D code that shall be used in delayed RINs generated shall be the D 

code specified in Table 1 to §80.1426 which corresponds to the pathway 

that describes the producer's operations. 

3. Section 80.1454 is proposed to be amended by revising paragraph (g) introductory 

text to read as follows: 

§ 80.1454 What are the recordkeeping requirements under the RFS Program?

* * * * * 
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(g) Aggregate compliance with renewable biomass requirement. Any producer or 

RIN-generating importer of renewable fuel made from planted crops or crop 

residue from existing U.S. agricultural land as defined in §80.1401, or any 

producer or RIN-generating importer of renewable fuel made from feedstock 

covered by a petition approved pursuant to §80.1457, is subject to the aggregate 

compliance approach and is not required to maintain feedstock records unless 

EPA publishes a finding that the 2007 baseline amount of agricultural land has 

been exceeded or that the criterion in §80.1457(a) is no longer satisfied. 

* * * * * 

4. Section 80.1457 is proposed to be added to read as follows: 

§ 80.1457 Petition Process for International Aggregate Compliance Approach 

 (a) EPA may approve a petition for application of the aggregate compliance approach 

to non-U.S. planted crops and crop residues from existing foreign agricultural 

land if it determines that an aggregate compliance approach will provide 

reasonable assurance that specified renewable fuel feedstocks from a given 

geographical area meet the definition of renewable biomass and will continue to 

meet the definition of renewable biomass, based on the submission of credible, 

reliable, and verifiable data. 

(1) As part of its evaluation, EPA will consider: 

(i) Whether there has been a reasonable identification of the aggregate 

amount of agricultural land in the specified geographical area as of 

December 19, 2007 that was available for the production of the 

specified feedstock(s) and that satisfy the definition of renewable 

biomass; 

(ii) Whether information from years preceding and following 2007 

shows that the 2007 amount of agricultural land identified in 

paragraph (a)(1)(i) of this section is not likely to be exceeded in the 

future; 

(iii) Whether economic considerations, legal constraints, historical land 

use and agricultural practices, and/or other factors show that it is 

likely that producers of the feedstock(s) will continue to use 

agricultural land within area of land identified in paragraph 

(a)(1)(i) of this section in the future as opposed to clearing and 

cultivating land that was not included in that area of land. 

(iv) Whether there is a reliable method to evaluate on a continuing 

basis whether the 2007 area of land identified in paragraph (a)(1)(i) 

of this section is being exceeded; and 

(v) Whether an entity has been identified to conduct data gathering 

and analysis needed for the evaluation specified in paragraph 
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(a)(1)(iv) of this section, for submission to EPA on an annual basis 

if EPA grants the petition. 

(2) [Reserved] 

(b) Any petition submitted under paragraph (a) of this section must be in the English 

language, and must include all of the following, or an explanation of why it is not 

needed for EPA to approve the petition: 

(1) Maps or electronic data identifying the boundaries of the land for which 

the petitioner seeks approval of an aggregate compliance approach. 

(2) (i) For petitions regarding crops or crop residue, the total amount of 

land that is cropland or pastureland within the geographic 

boundaries specified in paragraph (b)(1) of this section that was 

cleared or cultivated prior to December 19, 2007 and that was 

actively managed or fallow and nonforested on that date, and the 

total amount of land that is cropland or pastureland within the 

geographic boundaries specified in paragraph (b)(1) of this section 

that was not cleared or cultivated prior to December 19, 2007 and 

actively managed or fallow and nonforested on that date. 

(ii) If the petitioner is seeking approval of the aggregate compliance 

approach for a particular planted crop or crop residue, the total 

amount of land within the geographic boundaries specified in 

paragraph (b)(1) of this section that was used for the production of 

that feedstock in 2007 and that was actively managed or fallow and 

nonforested on that date, and the total amount of land within the 

geographic boundaries specified in paragraph (b)(1) of this section 

that was used for the production of that feedstock in 2007 that was 

not cleared or cultivated prior to December 19, 2007 and actively 

managed or fallow and nonforested on that date.. 

(3) A description of the feedstock(s) for which the petitioner is submitting the 

petition. 

(4) Land use data that demonstrates that the land in question in paragraph 

(b)(1)of this section is cropland or pastureland that was cleared or 

cultivated prior to December 19, 2007 and that was actively managed or 

fallow and nonforested on that date, which may include any of the 

following: 

 (i) Satellite imagery data. 

 (ii) Aerial photography. 

 (iii) Census data. 

 (iv) Agricultural surveys. 

 (v) Agricultural economic modeling data. 
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(5) Historical land use data for the land within the geographic boundaries 

specified in paragraph (b)(1) of this section to the current year, which may 

include any of the following: 

(i) Satellite imagery data. 

 (ii) Aerial photography. 

 (iii) Census data. 

 (iv) Agricultural surveys. 

 (v) Agricultural economic modeling data. 

(6) A description of any applicable laws, agricultural practices, economic 

considerations, or other relevant factors that had or may have an effect on 

the use of the land within the geographic boundaries specified in 

paragraph (b)(1) of this section. 

(7) A plan describing how the petitioner will identify an entity who will, on a 

continuing basis, conduct data gathering, analysis, and submittal to assist 

EPA in making an annual determination of whether the criterion specified 

in paragraph (a) of this section remains satisfied. 

(8) Any additional information the Administrator may require. 

(c) If EPA approves a petition it will issue a Federal Register notice announcing its 

decision and specifying an effective date for the application of the aggregate 

compliance approach to the specified feedstock(s) from the specific geographical 

area. Thereafter, the specified feedstocks from the specified area will be covered 

by the aggregate compliance approach set forth in §80.1454(g), or as otherwise 

specified pursuant to paragraph (d) of this section. 

(d) If EPA grants a petition to establish an aggregate compliance approach for a 

specified feedstock(s) from a specific geographical area, it may include any 

conditions that EPA considers appropriate in light of the conditions and 

circumstances involved. 

(e) (1) EPA may withdraw its approval of the aggregate approach for the area and 

feedstocks in question if: 

(i) EPA determines that the data submitted pursuant to the plan 

described in paragraph (b)(7) of this section does not demonstrate 

that the amount of cropland and pastureland within the geographic 

boundaries covered by the approved petition does not exceed the 

2007 baseline amount of land; 

(ii) EPA determines based on other information that the criterion 

specified in paragraph (a) of this section is no longer satisfied; or 
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(iii) EPA determines that the data needed for its annual evaluation has 

not been collected and submitted in a timely and appropriate 

manner. 

(2) If EPA withdraws its approval, then producers using feedstocks from that 

area will be subject to the individual recordkeeping and reporting 

requirements of §80.1454(b) through (d) in accordance with the schedule 

specified in §80.1454(g).