Tuesday, 

July 20, 2010 

Part III 

Environmental 

Protection Agency 

40 CFR Part 80 

Regulation of Fuels and Fuel Additives: 

2011 Renewable Fuel Standards; Proposed 

Rule 


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ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 80 

[EPA–HQ–OAR–2010–0133; FRL–9175–8] 

RIN 2060–AQ16 

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 August 19, 2010. 

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: 

• http://www.regulations.gov: Follow 

the online instructions for submitting 

comments. 

• E-mail: asdinfo@epa.gov. 

• Mail: Air and Radiation Docket and 

Information Center, Environmental 

Protection Agency, Mailcode: 2822T, 

1200 Pennsylvania Ave., NW., 

Washington, DC 20460. 

• 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 http:// 

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 http:// 

www.regulations.gov or e-mail. The 

http://www.regulations.gov Web site is 

an ‘‘anonymous access’’ system, which 

means EPA will not know your identity 

or contact information unless you 

provide it in the body of your comment. 

If you send an e-mail comment directly 

to EPA without going through http:// 

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 http:// 

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 http:// 

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; E-mail address asdinfo@epa.gov. 

SUPPLEMENTARY INFORMATION: 

I. General Information 

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 SIC 2 codes Examples of potentially regulated entities 

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

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

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

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

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

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


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1 75 FR 14670. 

Category NAICS1 codes SIC 2 codes Examples of potentially regulated entities 

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

1 North American Industry Classification System (NAICS). 

2Standard Industrial Classification (SIC) system code. 

This table is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

regulated by this 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 http://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 

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 

A. Statutory Requirements for Cellulosic 

Biofuel 

B. Assessment of 2011 Cellulosic Biofuel 

Volume 

C. Advanced Biofuel and Total Renewable 

Fuel 

D. Proposed Percentage Standards 

II. Volume Production and Import Potential 

for 2011 

A. Cellulosic Biofuel 

1. Domestic Cellulosic Ethanol 

2. Domestic Cellulosic Diesel 

3. Other Domestic Cellulosic Biofuels 

4. Imports of Cellulosic Biofuel 

5. Summary of Volume Projections 

B. Potential Limitations 

C. Advanced Biofuel and Total Renewable 

Fuel 

D. Biomass-Based Diesel 

III. Proposed Percentage Standards for 2011 

A. Background 

B. Calculation of Standards 

1. How are the standards calculated? 

2. Small Refineries and Small Refiners 

IV. Cellulosic Biofuel Technology 

Assessment 

A. What pathways are valid for the 

production of cellulosic biofuel? 

B. Cellulosic Feedstocks 

C. Emerging Technologies 

1. Biochemical 

a. Feedstock Handling 

b. Biomass Pretreatment 

c. Hydrolysis 

i. Acid Hydrolysis 

ii. Enzymatic Hydrolysis 

d. Fuel Production 

e. Fuel Separation 

f. Process Variations 

g. Current Status of Biochemical 

Conversion Technology 

h. Major Hurdles to Commercialization 

2. Thermochemical 

a. Ethanol Based on a Thermochemical 

Platform 

b. Diesel and Naphtha Production Based on 

a Thermochemical Platform 

3. Hybrid Thermochemical/Biochemical 

Processes 

4. Pyrolysis and Depolymerization 

a. Pyrolysis Diesel Fuel and Gasoline 

b. Catalytic Depolymerization 

5. Catalytic Reforming of Sugars to 

Gasoline 

V. Proposed Changes to RFS2 Regulations 

A. Delayed RIN Generation for New 

Pathways 

B. Criteria and Process for Adoption of 

Aggregate Approach to Renewable 

Biomass for Foreign Countries 

1. Criterion and Considerations 

2. Data Sources 

3. Petition Submission 

4. Petition Process 

VI. Public Participation 

A. How do I submit comments? 

B. How should I submit CBI to the agency? 

VII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer 

Advancement Act 

J. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

VIII. Statutory Authority 

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, 2010 1. 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 in-depth 

evaluation of the volume of qualifying 

cellulosic biofuel that can be supplied 

in the following year. If the projected 


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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 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 a 0.25 

Biomass-based diesel .................................................................................................................................................. 0.80 1.20 

Advanced biofuel ......................................................................................................................................................... 1.35 1.35 

Renewable fuel ............................................................................................................................................................ 13.95 13.95 

aThis value assumes that all cellulosic biofuel would be ethanol. If any portion of the renewable fuel used to meet the cellulosic biofuel volume 

mandate has a volumetric energy content greater than that for ethanol, this value will be higher. 

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 


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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 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 

ethanol-equivalent 

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. 

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 

ethanol-equivalent 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 


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2The March 2010 issue of STEO was used for 

today’s proposal. We intend to use the October 2010 

version for the final rule. 

3EIA 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. 

4The 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. 

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, 

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 nonrenewable gasoline and diesel volume. 

The projected volumes of gasoline and 

renewable fuels used to calculate the 

standards are provided by EIA’s ShortTerm 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 2011 4, 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—PROPOSED

PERCENTAGE STANDARDS FOR 2011 

Percent 

Cellulosic biofuel ................... 0.004–0.015 

Biomass-based diesel .......... 0.68 

Advanced biofuel .................. 0.77 

Renewable fuel ..................... 7.95 

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 


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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 publicly 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 

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. In order for this volume of 

cellulosic biofuel to be produced in 

2011, each of the companies discussed 

below would have to achieve their 

production targets in their projected 

timeframes. However, historical trends 

among cellulosic biofuel producers 

suggests that this is unlikely to be the 

case, as there are many factors which 

have the potential to result in 

production delays. For instance, several 

of the companies we considered when 

setting the 2010 cellulosic biofuel 

standard have yet to sell cellulosic 

biofuel in the United States and appear 

unlikely to do so by the end of 2010. 

This fact demonstrates the uncertainty 

of cellulosic biofuel production 

estimates, and is one of many factors 

EPA will consider when setting the 

cellulosic biofuel standard for 2011. 

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 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 


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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 plans 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 

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 could, at most, 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 BioEnergy. 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 BioEnergy is successful in producing and 

upgrading their fuel EPA estimates the 

maximum volume of fuel they could 

produce in 2011 would be 7 million 

gallons (11.9 million ethanol equivalent 

gallons) of jet or diesel fuel. 

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 pretreatment 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 could provide as 

much as 250,000 gallons of cellulosic 

ethanol in 2011 based on production 

volumes from previous years. 


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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. 

TABLE II.A.5–1—CELLULOSIC BIOFUEL MAXIMUM 2011 POTENTIALLY AVAILABLE VOLUME

Company name Location Feedstock Fuel Capacity 

(MGY) 

Earliest 

production 

Maximum 

2011 potentially available 

volume 

(MG) 

Ethanol 

equivalent 

gallons 

(MG) 

AE Advanced 

Fuels Keyes.

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 

cellulosic biomass.

Diesel Feedstock 14.4 June 2011 .... 7 11.9 

Cello Energy ...... Bay Minette, AL Wood, hay ......... Diesel ................ 20 Online ........... 5 8.5 

DuPont Danisco a Vonore, TN ........ Corn cobs, then 

switchgrass.

Ethanol .............. 0.25 Online ........... 0.15 0.15 

Fiberight a ........... Blairstown, IA .... MSW .................. Ethanol .............. 6 April 2010 ..... 2.8 2.8 

Iogen .................. Ottawa, Ontario Wheat, oat & 

barley straw.

Ethanol .............. 0.5 Online ........... 0.25 0.25 

KL Energy a ........ Upton, WY ......... Wood ................. Ethanol .............. 1.5 Online ........... 0.4 0.4 

Total ............ ............................ ............................ ............................ ........................ ...................... 17.1 25.5 

a Maximum Production/Import Potential represents company estimate. 

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, as stated earlier, in order for 

this volume of cellulosic biofuel to be 

produced in 2011, each of the 

companies listed in Table II.A.5–1 

would have to achieve their production 

targets in their projected timeframes. 

The history of the cellulosic biofuels 

industry has many examples of delays 

in achieving full production capacity in 

new facilities. 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 volume. 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 


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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. 

6For more information on the annual production 

outlook reports see § 80.1449 of the RFS2 

regulations. 

7 Kinder Morgan announcement that their Central 

Florida Pipeline from Tampa to Orlando ships 

batches of ethanol along with batches of gasoline. 

http://www.kindermorgan.com/business/ 

products_pipelines/. 

8 ‘‘POET Joins Magellan Midstream Partners to 

Assess Dedicated Ethanol Pipeline’’, March 2009, 

http://www.poet.com/news/ 

showRelease.asp?id=155. 

September 1, 2010 5 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 years.6 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 in 2011. 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. 

Although we are currently projecting 

that the potentially available volume of 

cellulosic biofuel in 2011 will be in the 

range of 6.5 to 25.5 million ethanolequivalent 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. 

For instance, a short gasoline pipeline 

in Florida is currently shipping batches 

of ethanol.7 Evaluations are also 

currently underway regarding the 

feasibility of constructing a new 

dedicated ethanol pipeline from the 

Midwest to the East coast.8 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 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] 

Ethanolequivalent 

volume 

Physical 

volume 

Total renewable 

fuel ................ 13,950 13,500– 

13,549 

Conventional renewable fuel a 12,600 12,600 

Total advanced 

biofuel ............ 1,350 900–949 

Cellulosic biofuel 6.5–25.5 5–17.1 

Biomass-based 

diesel ............. 1200 800 

Other advanced 

biofuel b ......... 125–144 83 c–144 d

aPredominantly 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. 


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9 ‘‘Monthly U.S. Imports of Fuel Ethanol,’’ EIA, 

released 4/8/2010. 

10Lundell, Drake, ‘‘Brazilian Ethanol Export 

Surge to End; U.S. Customs Loophole Closed Oct. 

1,’’ Ethanol and Biodiesel News, Issue 45, November 

4, 2008. 

11Renewable Fuels Association (RFA), ‘‘2008 

World Fuel Ethanol Production,’’ http:// 

www.ethanolrfa.org/industry/statistics/#E, March 

31, 2009. 

12EIA STEO, June 2010, Table 8. 

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. 

TABLE II.C–2—HISTORICAL IMPORTS

OF ETHANOL

[Mill gallons] 9

2007 .................................................. 439 

2008 .................................................. 530 

2009 .................................................. 194 

Brazilian imports have made up a 

sizeable portion of total ethanol 

imported into the U.S. However, as 

shown above, these import volumes 

decreased significantly in 2009. Part of 

the reason for this decline in imports is 

the cessation of the duty drawback that 

became effective on October 1, 2008, but 

also changes in world sugar prices.10

However, Brazil produces the most 

ethanol in the world, reaching about 9 

billion gallons in 2008.11 Thus if there 

were a demand in the U.S. in 2011 for 

125–144 million gallons of advanced 

biofuel, it may be economical for Brazil 

to export at least this volume of 

sugarcane ethanol to the U.S. 

EIA’s projections for 2011 suggest that 

there may be sufficient 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] 12

Imported ethanol ............................... 202 

Total domestic biodiesel production 860 

Biodiesel needed to meet biomassbased diesel standard ................... 800 

Excess biodiesel ............................... 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 202 million gallons of 

imported sugarcane ethanol. The total 

would therefore be 292 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, 292 million gallons would likely 

be sufficient. Moreover, 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 goes into effect in 2011, 

and may compel some refiners to import 

additional volumes of sugarcane ethanol 

from Brazil into California. 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 such as waste 

cooking oil or restaurant grease used as 

a diesel fuel additive. Finally, 

additional market demand for imported 

sugarcane ethanol and biodiesel would 

likely 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. 

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 cornethanol, 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 1,206 million gallons, 

we would expect the amount of cornethanol 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 1050 million 

gallons. See Table II.C–4. 

TABLE II.C–4—PROJECTED EXCESS

CORN ETHANOL IN 2011 

[Mill gallons] 

Total domestic corn ethanol production 13 ............................................. 13,650 

Corn ethanol needed to meet total 

renewable fuel standard ............... 12,600 

Excess corn ethanol ......................... 1050 

13EIA STEO, June 2010, Table 8. 

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 


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42248 Federal Register / Vol. 75, No. 138 / Tuesday, July 20, 2010 / Proposed Rules 

14Figures taken from National Biodiesel Board 

list of operating plants as of April 5, 2010. 

15 Data taken from Energy Information 

Administration Monthly Energy Review, Table 10.4, 

March 2010. 

16Project status updates are available via the 

Syntroleum Web site, http://dynamicfuelsllc.com/ 

wp-news/. 

will directly affect our consideration of 

adjustments to the volumetric 

requirements for advanced biofuel and 

total renewable fuel. 

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.14 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 

inFigure II.D–1. 

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 biomassbased 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 

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.16

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. Indications from the biodiesel 

industry are that these idled facilities 

can be brought back into production 

with a relatively short leadtime, and can 

thus 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 


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17See Federal Register v.74 n.99 p.24903. 

Comments are available in docket EPA–HQ–OAR– 

2005–0161. 

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.17

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): 

Std

RFV

CB i

CB i

,

, = × % ( ) − + − ( ) − +− ( ) + −

100

G RG GS RGS GE D RD DS R i i i i ii i i DS DE

G RG GS RGS GE

i i

ii i i

( ) −

= ×

×

( ) − + − ( ) − Std

RFV

BBD i

BBD i

,

, % . 100

1 5

ii i i i i

ii i

D RD DS RDS DE

G RG GS

+ − ( ) + − ( ) −

= × ( ) − +

Std

RFV

AB i

AB i

,

, %100 ( ) − − +− ( ) + − ( ) −

= ×

RGS GE D RD DS RDS DE

G

i ii i i i i

i

Std

RFV

RF i

RF i

,

, %100 ( ) − RG GS RGS GE D RD DS RDS DE i i i ii i i i 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. 

RDi = Amount of renewable fuel blended into 

diesel that is projected to be consumed 


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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 ShortTerm 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. 

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 biomassbased diesel standard based on biodiesel 

equivalence. However, all RIN 

generation is based on ethanolequivalence. 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 

biomass-based diesel will be created in 

2011, the calculation of the biomassbased 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 

non-renewable 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 gallons] 

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. 

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 


wwoods2 on DSKDVH8Z91PROD with PROPOSALS3
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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-by-case 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-bycase 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. 

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 wastes; and cellulosic 

components of separated MSW.

Any ...................................... 3 (cellulosic biofuel). 

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 FischerTropsch 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 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 


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42252 Federal Register / Vol. 75, No. 138 / Tuesday, July 20, 2010 / Proposed Rules 

18 DOE. ‘‘Biomass Program: ABC’s of Biofuels’’. 

Accessed at: http://www1.eere.energy.govbiomass/ 

abcs_biofuels.html#content. 

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%).18 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). 

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 

Biochemical .............................. 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. 

One step Conversion of Cellulose to 

distillate.

Diesel, Jet Fuel or Naphtha ... Bell Bioenergy, LS9. 

Thermochemical ....................... 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/Catalytic conversion 

of syngas to alcohols.

Ethanol ................................... Range Fuels, Pearson Technologies, 

Fulcrum Bioenergy, Enerkem, and 

Gulf Coast Energy. 

Hybrid ....................................... Thermochemical w/Biochemical catalyst.Ethanol ................................... Coskata, INEOS Bio. 

Acid Hydrolysis of cellulose to intermediate; hydrogenation using 

Thermochemical syngas from noncellulose fraction.

Ethanol, Other alcohols .......... Zeachem. 

Depolymerization ...................... Catalytic Depolymerization of Cellulose.Diesel, Jet Fuel or Naphtha ... 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. 

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 


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Federal Register / Vol. 75, No. 138 / Tuesday, July 20, 2010 / Proposed Rules 42253 

19 Image From: http://www.afdc.energy.gov/afdc/

ethanol/production_cellulosic.html. 

20Wyborny, Lester. ‘‘In-Depth Assessment of 

Advanced Biofuels Technologies.’’ Memo to the 

docket, May 2010. 

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. 

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 docket 20, 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 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, 

such as dirt, rocks, plastics, metals, and 

other non-biogenic materials, 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). 


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42254 Federal Register / Vol. 75, No. 138 / Tuesday, July 20, 2010 / Proposed Rules 

21Wyborny, Lester. ‘‘In-Depth Assessment of 

Advanced Biofuels Technologies.’’ Memo to the 

docket, May 2010. 

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 

docket.21 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 

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 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 


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Federal Register / Vol. 75, No. 138 / Tuesday, July 20, 2010 / Proposed Rules 42255 

22Wyborny, Lester. ‘‘In-Depth Assessment of 

Advanced Biofuels Technologies.’’ Memo to the 

docket, May 2010. 

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 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 

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 Co-Fermentation 

(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 docket.22 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 


wwoods2 on DSKDVH8Z91PROD with PROPOSALS3
42256 Federal Register / Vol. 75, No. 138 / Tuesday, July 20, 2010 / Proposed Rules 

23U.S. DOE. Technologies: Processing and 

Conversion. Accessed at: http:// 

www1.eere.energy.gov/biomass/ 

processing_conversion.html on October 28, 2008. 

24EERE, 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. 

25Aden, Andy, Mixed Alcohols from Woody 

Biomass—2010, 2015, 2022, National Renewable 

Energy Laboratory (NREL), September 23, 2009. 

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. 

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 

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.23 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, non-fermentable material 

left over from high-starch or cellulosic 

feedstocks conversion.24 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 long-term 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 mixed-alcohols route 

refer to NREL technical 

documentation.25


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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. 


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42258 Federal Register / Vol. 75, No. 138 / Tuesday, July 20, 2010 / Proposed Rules 

26Lin 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. 

27S. 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. 

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.26 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 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 super-heaters 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.27 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 technoeconomic 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., 

n-propanol, n-butanol, and n-pentanol). 

The by-product higher normal alcohols 

have value as commodity chemicals and 

fuel additives. 

The liquid rundown from the lowpressure 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 

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 Canadianbased 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 threestage gasification reactor includes low 

temperature gasification, high 


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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 U.S. 

Choren is also planning to build a 

commercial thermochemical/biomassto-liquids (BTL) plant in the U.S. after 

their Freiberg/Saxony plant is 

operational in Germany. 

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. 

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, farmgrown 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 


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28 DOE EERE Biomass Program. ‘‘Thermochemical 

Conversion Processes: Pyrolysis’’ http:// 

www1.eere.energy.gov/biomass/ 

thermochemical_processes.html, November 6, 2008. 

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, 

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.28 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 bio-fuels 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. 

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. 

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 


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29 75 FR 14670, March 26, 2010. 

#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 

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 

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. 

V. Proposed Changes to RFS2 

Regulations 

Following publication of the final 

RFS2 program regulations ,29 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 


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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 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 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, nongrandfathered 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 


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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 within a country. The 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 nondomestically grown feedstocks. The 

existing approved aggregate approach 

for U.S. domestic feedstocks applies to 

all crops and crop residue that could be 

used in renewable fuel 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 FR 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. 

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 


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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 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 closegrown 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 country, 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 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 


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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. Additionally, 

EPA requests comment on whether the 

burden associated with the petition 

process is reasonable, and how it might 

be minimized while still remaining 

adequately robust. Specific estimates 

about the time and cost of preparing a 

petition will be published in 

Information Collection Request 

associated with this proposed 

rulemaking. 

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, 

http://www.regulations.gov, or by email. 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. 

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. 

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 

The information collection 

requirements in this proposed rule have 

been submitted for approval to the 

Office of Management and Budget 

(OMB) under the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. The 

Information Collection Request (ICR) 

document prepared by EPA has been 

assigned EPA ICR number 2398.01. 

This proposed regulation has a 

provision that EPA would use to 

authorize renewable fuel producers 

using foreign-grown feedstocks to use an 

aggregate approach to comply with the 

renewable biomass verification 

provisions, similar to that applicable to 

producers using crops and crop residue 

grown in the United States. See 

discussion in Section V.B. For this 

authorization, foreign based entities 

could 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 within 

a country. This petition request for 

crops from foreign grown land areas 

would be voluntary. If approved by 

EPA, such a petition would allow 

biomass produced in a foreign country 

or geographical area to be counted as 

feedstock to make renewable fuel under 

the RFS2 program. Other actions in this 

proposed regulation would not impose 

any new information collection burdens 

on regulated entities beyond those 

already required under RFS2. The 

submission of this information is 

required in order for EPA to evaluate 

and act on the petitions. Respondents 

may assert claims of business 

confidentiality (CBI) for any or all of the 

information they submit. We do not 

believe that most respondents would 

characterize the information they 

submit to us under this information 

collection as CBI. However, any 

information claimed as confidential 

would be treated in accordance with 40 

CFR Part 2 and established Agency 

procedures. Information that is received 

without a claim of confidentiality may 

be made available to the public without 

further notice to the submitter under 40 

CFR 2.203. 

EPA estimates that there would be 15 

respondents (petitioners), submitting 15 

responses (petitions) in response to this 

provision. The estimated burden annual 


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burden, assuming 15 respondents, 

would be 200 hours and annual cost is 

$14,196. Burden is defined at 5 CFR 

1320.3(b). 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. 

To comment on the Agency’s need for 

this information, the accuracy of the 

provided burden estimates, and any 

suggested methods for minimizing 

respondent burden, EPA has established 

a public docket for this rule, which 

includes this ICR, under Docket ID 

number EPA–HQ–OAR–2010–0133. 

Submit any comments related to the ICR 

to EPA and OMB. See ADDRESSES

section at the beginning of this notice 

for where to submit comments to EPA. 

Send comments to OMB at the Office of 

Information and Regulatory Affairs, 

Office of Management and Budget, 725 

17th Street, NW., Washington, DC 

20503, Attention: Desk Office for EPA. 

Since OMB is required to make a 

decision concerning the ICR between 30 

and 60 days after July 20, 2010, a 

comment to OMB is best assured of 

having its full effect if OMB receives it 

by August 19, 2010. The final rule will 

respond to any OMB or public 

comments on the information collection 

requirements contained in this proposal. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of today’s rule on small entities, small 

entity is defined as: (1) A small business 

as defined by the Small Business 

Administration’s (SBA) regulations at 13 

CFR 121.201; (2) a small governmental 

jurisdiction that is a government of a 

city, county, town, school district or 

special district with a population of less 

than 50,000; and (3) a small 

organization that is any not-for-profit 

enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of 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 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 

104–113, 12(d) (15 U.S.C. 272 note) 

directs EPA to use voluntary consensus 

standards in its regulatory activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impractical. Voluntary consensus 

standards are technical standards (e.g., 

materials specifications, test methods, 

sampling procedures, and business 

practices) that are developed or adopted 

by voluntary consensus standards 

bodies. NTTAA directs EPA to provide 

Congress, through OMB, explanations 

when the Agency decides not to use 

available and applicable voluntary 

consensus standards. 


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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. 

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: July 9, 2010. 

Lisa P. Jackson, 

Administrator. 

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)(7) 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. 

(2) Delayed RINs must be generated 

within 30 days of the effective date of 

the rule in which the pathway is added. 

(3) Delayed RINs may only be 

generated to represent renewable fuel 

produced or imported between July 1, 

2010 and the effective date of the rule 

in which the pathway is added. 

(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. 

(i) The number of gallon-RINs retired 

must not exceed the number of gallonRINs originally generated to represent 

the renewable fuel volumes produced or 

imported between July 1, 2010 and the 

effective date of the rule in which the 

pathway is added. 

(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 gallonRINs 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 gallonRINs 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 effective 

date of the rule in which the pathway 

is added. 

(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 amended by 

revising paragraph (g) introductory text 

to read as follows: 

§ 80.1454 What are the recordkeeping 

requirements under the RFS Program? 

* * * * * 

(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 RINgenerating 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 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 


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42268 Federal Register / Vol. 75, No. 138 / Tuesday, July 20, 2010 / Proposed Rules 

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 (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. 

(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 

(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). 

[FR Doc. 2010–17281 Filed 7–19–10; 8:45 am] 

BILLING CODE 6560–50–P 


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