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EO12866_CAA 211o 2060-AQ16 FRM FRN 20101117 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 80 

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

RIN 2060-AQ16 

Regulation of Fuels and Fuel Additives: 2011 Renewable Fuel Standards 

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Final Rule. 

SUMMARY: 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 the Energy Information Administration (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, if the projected volume is less than the applicable volume 

provided in the statute. These cellulosic biofuel volume projections are to be based in 
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part on EIA projections as well as assessments of production capability from industry. 

This action establishes annual percentage standards under Clean Air Act section 211(o) 

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

apply to all gasoline and diesel produced or imported in calendar year 2011. We have 

determined that the applicable volume of cellulosic biofuel on which the percentage 

standard should be based is 6.0 million ethanol-equivalent gallons. We believe that 

available volumes of cellulosic biofuel could be significantly higher in 2012. This action 

also finalizes two changes to the Renewable Fuel Standard program regulations: 

modifications to the delayed RINs provision which provides a temporary and limited 

means for certain renewable fuel producers to generate RINs after they have produced 

and sold renewable fuel, and a new process for parties to petition EPA to authorize use of 

an aggregate approach to compliance with the renewable biomass provision for foreign 

feedstocks akin to that applicable to the U.S. Finally, this action makes two 

administrative announcements, one regarding the price for cellulosic biofuel waiver 

credits for 2011, and another regarding the status of the aggregate compliance provision 

for domestic crops. 

DATES: This final rule is effective on [insert date of publication in the federal 

register]. 

ADDRESSES: EPA has established a docket for this action under Docket ID No. EPAHQ-OAR-2010-0133. All documents in the docket are listed on the 

www.regulations.gov website. Although listed in the index, some information is not 
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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 through 

www.regulations.gov or in hard copy at the Air and Radiation Docket and Information 

Center, EPA/DC, EPA West, Room 3334, 1301 Constitution Ave., NW, Washington, 

DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through 

Friday, excluding legal holidays. The telephone number for the Public Reading Room is 

(202) 566-1744, and the telephone number for the Air Docket is (202) 566-1742. 

FOR FURTHER INFORMATION CONTACT: Julia MacAllister, Office of 

Transportation and Air Quality, Assessment and Standards Division, Environmental 

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

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

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

SUPPLEMENTARY INFORMATION: 

I. General Information 

A. Does this Action Apply to Me? 
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Entities potentially affected by this final rule are those involved with the 

production, distribution, and sale of transportation fuels, including gasoline and diesel 

fuel or renewable fuels such as ethanol and biodiesel. Potentially regulated categories 

include: 

Category NAICS1

Codes 

SIC2

Codes 

Examples of Potentially Regulated Entities 

Industry 

Industry 

Industry 

Industry 

Industry 

Industry 

 

Industry 

324110 

325193 

325199 

424690 

424710 

424720 

454319 

2911 

2869 

2869 

5169 

5171 

5172 

5989 

Petroleum Refineries 

Ethyl alcohol manufacturing 

Other basic organic chemical manufacturing 

Chemical and allied products merchant wholesalers 

Petroleum bulk stations and terminals 

Petroleum and petroleum products merchant 

wholesalers 

Other fuel dealers 

1

 North American Industry Classification System (NAICS) 

2

 Standard Industrial Classification (SIC) system code. 

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

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

entities that EPA is now aware could potentially be regulated by this action. Other types 

of entities not listed in the table could also be regulated. To determine whether your 

activities will be regulated by this action, you should carefully examine the applicability 
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criteria in 40 CFR part 80. If you have any questions regarding the applicability of this 

action to a particular entity, consult the person listed in the preceding section. 

Outline of this preamble 

I. Executive Summary

A. Statutory Requirements for Renewable Fuel Volumes

B. Assessment of 2011 Cellulosic Biofuel Production

C. Advanced Biofuel and Total Renewable Fuel

D. Final Percentage Standards

E. 2011 Price for Cellulosic Biofuel Waiver Credits

F. Assessment of the Aggregate Compliance Approach

II. Volume Production and Import Potential for 2011

A. Cellulosic Biofuel

1. Domestic Cellulosic Biofuel

2. Imports of Cellulosic Biofuel

3. Projections from the Energy Information Administration

4. Overall 2011 Volume Projections

5. Projections of Cellulosic Biofuel for 2012

B. Advanced Biofuel and Total Renewable Fuel

C. Biomass-Based Diesel
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III. 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 Currently 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. Path to Commercialization

2. Thermochemical

a. Ethanol based on a Thermochemical Platform

b. Diesel and Naphtha Production based on a Thermochemical Platform
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3. Hybrid Thermochemical/Biochemical Processes

a. Biochemical Step Following Thermochemical Step

b. Concurrent Biochemical and Thermochemical Steps

4. Pyrolysis and Depolymerization

a. Pyrolysis Diesel Fuel and Gasoline

b. Catalytic Depolymerization

5. Catalytic Reforming of Sugars to Gasoline

V. Changes to RFS Regulations

A. Delayed RIN Generation for New Pathways

B. Aggregate Compliance Approach for Renewable Biomass from Foreign Countries

1. Criteria and Considerations

2. Applicability of the Aggregate Approach

3. Data Sources

4. Petition Submission

5. Petition Process

VI. Annual Administrative Announcements

A. 2011 Price for Cellulosic Biofuel Waiver Credits

B. Assessment of the Domestic Aggregate Compliance Approach

VII. Comments Outside the Scope of This Rulemaking

VIII. Public Participation

IX. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review
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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

K. Congressional Review Act

X. Statutory Authority
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I. Executive Summary 

 EPA issued comprehensive regulations in 2007 to implement the Renewable Fuel 

Standard (RFS1) program in Section 211(o) of the Clean Air Act, as required by 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 publication of revised regulatory requirements (RFS2) on March 

26, 20101

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

requirements of EISA occurred on July 1, 2010. 

 EPA is required to determine and publish the applicable annual percentage 

standards for cellulosic biofuel, biomass-based diesel, advanced biofuel and total 

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

determination of the applicable cellulosic biofuel standard under RFS2 requires that EPA 

first project the volume of cellulosic biofuel production for the following year. If the 

projected volume of cellulosic biofuel production is less than the applicable volume 

specified in Section 211(o)(2)(B)(i)(III) of the statute, EPA must lower the required 

volume used to set the annual cellulosic biofuel percentage standard to the projected 

available volume. If we lower the applicable cellulosic biofuel volume, we must also 

determine whether the advanced biofuel and/or total renewable fuel volumes should be 

reduced by the same or a lesser amount. We provided our volume projections and 

proposed percentage standards for 2011 in a Notice of Proposed Rulemaking (NPRM) on 

July 20, 2010 (75 FR 42238). Today's action provides our final projection of cellulosic 

 

1

 75 FR 14670 
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biofuel production for 2011, and final percentage standards for all four categories of 

renewable fuel for compliance year 2011. The final 2011 standards have been based 

upon statutory requirements, comments received in response to the NPRM, the estimate 

of projected gasoline, diesel, and biofuel volumes that the EIA provided to EPA on 

October 20, 2010, and other relevant information. 

 Today's rule does not include an assessment of the impacts of the standards we 

are finalizing for 2011. All of the impacts of the RFS2 program associated with the 

applicable volumes of biofuel specified in the statute were addressed in the RFS2 final 

rule published on March 26, 2010. 

 Today's notice also finalizes two changes to the general RFS2 program 

regulations. The first change modifies a regulatory provision for "delayed RINs" that we 

implemented through a previous action on September 28, 2010.2 This provision provides 

a temporary and limited means for certain renewable fuel producers to generate RINs 

after they have produced and sold renewable fuel. In today's action we are modifying 

this regulatory provision to be more broadly applicable as described more fully in Section 

V.A. The second regulatory provision we are finalizing today establishes a petition 

process and criteria for EPA to use in determining whether to authorize the use of an 

aggregate approach to verify that feedstocks from foreign countries meet the definition of 

renewable biomass that would be akin to that applicable to producers using crops and 

crop residue grown in the United States. Further discussion of these provisions can be 

found in Section V.B. 

 

2

 75 FR 59622 
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 Finally, in today's rulemaking we are announcing the price for cellulosic biofuel 

waiver credits, and are also announcing the results of our annual assessment of the 

aggregate compliance approach for U.S. crops and crop residue. These announcements 

are provided in Section VI. 

 A. Statutory Requirements for Renewable Fuel Volumes 

 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)(B). These 

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

Required Volumes in the Clean Air Act for 2011 (billion 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 

a

 This 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 lower.

By November 30 of each year, the EPA is required under CAA 211(o)(3)(B) to determine 

and publish in the Federal Register percentage standards for the following year that will 

ensure that the applicable volumes of renewable fuel are used. These standards are to be 

based in part on transportation fuel (i.e. gasoline and diesel) volume estimates provided 

by the Energy Information Administration (EIA). The calculation of the percentage 

standards is based on the formulas in 40 CFR §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 
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must be based upon the projected available volume rather than the applicable volume in 

the statute. In addition, if EPA reduces the applicable 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. 

B. Assessment of 2011 Cellulosic Biofuel Production 

 To estimate the projected available volume of cellulosic biofuel in the U.S. in 

2011, we researched 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. Further analysis and 

investigation allowed us to determine which ones were actually in a position to produce 

and make available any commercial volumes of cellulosic biofuel in 2011. In this 

process we also considered factors such as the current and expected state of funding, the 

status of the technology and contracts for feedstocks or product sales, and progress 

towards construction and production goals. This assessment formed the basis of our 

projection for potentially available 2011 volumes. 
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 In our assessment we evaluated both domestic and foreign sources of cellulosic 

biofuel. We determined that five U.S. facilities have the potential to make volumes of 

cellulosic biofuel commercially available for transportation use in the U.S. in 2011. We 

also identified three international facilities, two in Canada and one in Germany, that we 

expect will produce cellulosic biofuel in 2011. While these facilities may also be able to 

produce cellulosic volume in 2011, we determined that they are unlikely to make the fuel 

available to the U.S. market. Based on our assessment for this rulemaking, we are 

lowering the applicable volume of cellulosic biofuel for 2011 from the statutory volume 

of 250 million gallons to 6.0 million ethanol-equivalent gallons. This volume is the basis 

for the percentage standard we are setting for cellulosic biofuel in 2011. As with any 

projections of future production there is some uncertainty associated with these volumes. 

These uncertainties in our 2011 cellulosic volume projection are discussed in more detail 

in Section II.A. Nevertheless, we believe that 6.0 million ethanol-equivalent gallons 

represents a reasonable projection of potential 2011 cellulosic production volume for use 

in setting the standard. 

 

 EPA is currently aware of more than 20 facilities representing over 300 million 

gallons of production that are targeting commercial production of cellulosic biofuels in 

2012. As a result, although the cellulosic biofuel standard we are setting for 2011 is 

considerably less than the applicable volumes established in EISA, EPA believes there is 

reason for optimism when looking at the plans for the cellulosic biofuel industry in 2012 

and beyond. 
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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. Since we are setting the cellulosic biofuel standard 

significantly below the statutory volume of 250 million gallons, we also needed to 

evaluate whether we should 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 

potential in 2011, as biodiesel is currently the predominant form of biomass-based diesel. 

As discussed in Section II.C, 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 

billion gallons (150 million gallons), 6.0 million gallons will be met with cellulosic 

biofuel. Based on our analysis as described in Section II.B, we believe that there are 

sufficient sources of other advanced biofuel, such as additional biodiesel, renewable 

diesel, or imported sugarcane ethanol, such that the standard for advanced biofuel can 

remain at the statutory level of 1.35 billion gallons. We have also determined that there 
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is sufficient qualifying domestic corn ethanol production capacity to meet the balance of 

the total renewable fuel standard that is not satisfied with advanced biofuel. Therefore, 

in today's final rule neither the 2011 volumes for advanced biofuel nor total renewable 

fuel are being lowered below the volumes specified in the statute. 

D. Final 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 applicable volumes required on a nationwide basis. To calculate the percentage 

standard for cellulosic biofuel for 2011, we have used the volume of 6.0 million ethanolequivalent gallons (representing 6.6 million physical gallons). We are also specifying 

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. 
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Table I.D-1 

Final Volumes for 2011 

Actual Volume 

Ethanol Equivalent 

Volume 

Cellulosic biofuel 6.6 mill gal 6.0 mill gal 

Biomass-based diesel 0.80 bill gal 1.20 bill gal 

Advanced biofuel 1.35 bill gal 1.35 bill gal 

Renewable fuel 13.95 bill gal 13.95 bill gal 

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

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

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

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

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

volumes of gasoline and diesel used to calculate the standards are provided by EIA. 

Because small refiners and small refineries are also regulated parties beginning in 20113

, 

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 

 

3

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

disproportionately harmed by inclusion in the 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 refineries if DOE revises their study and provides a different 

conclusion, or we determine that an individual small refinery has demonstrated that it will suffer a 

disproportionate economic hardship under the RFS program. 
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participating in the program. The final standards for 2011 are shown in Table I.D-2. 

Detailed calculations can be found in Section III. 

 

Table I.D-2 

Final Percentage Standards for 2011 

Cellulosic biofuel 0.003% 

Biomass-based diesel 0.69% 

Advanced biofuel 0.78% 

Renewable fuel 8.01% 

E. 2011 Price for Cellulosic Biofuel Waiver Credits 

 Since we are reducing the required volume of cellulosic biofuel for 2011 below 

the applicable volume specified in the statute, EPA is required to offer biofuel waiver 

credits to obligated parties that can be purchased in lieu of acquiring cellulosic biofuel 

RINs. These waiver credits are not allowed to be traded or banked for future use, and are 

only allowed to be used to meet the 2011 cellulosic biofuel standard. Moreover, unlike 

cellulosic biofuel RINs, waiver credits may not be used to meet either the advanced 

biofuel standard or the total renewable fuel standard. For the 2011 compliance period, 

we are making cellulosic biofuel waiver credits available to obligated parties for end-ofyear compliance should they need them at a price of $1.13 per credit. Further discussion 

is provided in Section VI.A. 
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F. Assessment of the Aggregate Compliance Approach 

As part of the RFS2 regulations, EPA established an aggregate compliance 

approach for renewable fuel producers who use planted crops and crop residue from U.S. 

agricultural land. This compliance approach relieved such producers (and importers of 

such fuel) of the individual recordkeeping and reporting requirements otherwise required 

of producers and importers to verify that feedstocks used in the production of RINqualifying renewable fuel meet the definition of renewable biomass. EPA determined 

that 402 million acres of U.S. agricultural land was available in 2007 (the year of EISA 

enactment) for production of crops and crop residue that would meet the definition of 

renewable biomass, and determined that as long as this total number of acres is not 

exceeded, it is unlikely that new land has been devoted to crop production based on 

historical trends and economic considerations. We indicated that we would conduct an 

annual evaluation of total U.S. acreage that is cropland, pastureland, or conservation 

reserve program land, and that if the value exceed 402 million acres, producers using 

domestically-grown crops or crop residue to produce renewable fuel would be subject to 

individual recordkeeping and reporting to verify that their feedstocks meet the definition 

of renewable biomass. 

The RFS2 regulations provide that EPA will make a finding concerning whether 

the 2007 baseline amount of U.S. agricultural land has been exceeded in a given year and 
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will publish this finding in the Federal Register by November 30 of the same year. Based 

on data provided by the USDA, we have estimated that U.S. agricultural land reached 

398 million acres in 2010, and thus did not exceed the 2007 baseline acreage. 

We also stated in the preamble to the final RFS2 rule that if, at any point, EPA finds that 

the total agricultural land is greater than 397 million acres, EPA will conduct further 

investigations to evaluate validity of the domestic aggregate compliance approach. The 

total acreage estimate of 398 million acres exceeds the trigger point for further 

investigation, therefore EPA, with the help of USDA, will conduct further investigations 

into this matter. Additional discussion on this matter can be found in Section VI.B of this 

preamble. 
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II. Volume Production and Import Potential for 2011 

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

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

have the potential to produce qualifying cellulosic biofuel volumes for consumption as 

transportation fuel, heating oil, or jet fuel in the U.S. in 2011. We also evaluated the 

production and import potential for biomass-based diesels, advanced biofuels, and other 

conventional renewable fuels such as corn-ethanol. This section describes the volumes 

that we believe could potentially be produced or imported in 2011. As with any 

projections of future production there is some uncertainty associated with these volumes. 

Many of the uncertainties associated with our projected volumes are also discussed in this 

section. Section III describes the derivation of the percentage standards that will apply to 

obligated parties in 2011. 

 The 2011 volume projections in today's final rule are based on information from a 

wide spectrum of sources. For instance, EPA received input on our assessment of 2011 

production and import volumes from other government organizations including the 

Department of Energy (DOE), Energy Information Administration (EIA), and United 

States Department of Agriculture (USDA). The EIA projections of gasoline, diesel, 

biomass-based diesel, and cellulosic biofuel provided to EPA on October 20, 2010 were 

particularly germane. These EIA projections are discussed in more detail in Section 

II.A.3. 
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 We also received a number of comments related to our proposed volume 

projections and the associated percentage standards. With regard to the proposed 

cellulosic biofuel projections, most commenters agreed that the proposed range of 5 - 

17.1 million gallons (6.5 - 25.5 million ethanol-equivalent gallons) was appropriate, but 

no commenter suggested a specific volume for 2011 or a clear methodology for 

determining the appropriate volume. However, several commenters provided qualitative 

assessments. For instance, refiners suggested that the low end of the range would be 

more appropriate as it would minimize the possibility that obligated parties would be 

unable to procure sufficient cellulosic biofuel RINs to meet their obligations. They 

further stated that the cellulosic biofuel volume used to set the 2011 standard should be 

based on existing production volumes rather than a projection of potential volume in 

2011. In contrast, several proponents of the advanced biofuels industry stated that the 

cellulosic biofuel standard should be set as high as possible in order to establish the 

market demand that investors seek before funding cellulosic biofuel projects. They 

argued that the cellulosic biofuels industry is unlikely to grow without support in the 

form of a high cellulosic biofuel standard. 

 Since commenters did not provide their own quantitative assessments of projected 

cellulosic biofuel volumes for us to consider, we based our assessment of the production 

capabilities of planned and existing biofuel production facilities on projections provided 

by EIA as well as data provided by other government agencies and our own contact with 

many of these companies. In directing EPA to project cellulosic biofuel production for 

purposes of setting the annual cellulosic biofuel standard, Congress did not specify what 
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degree of certainty should be reflected in the projections. We believe that the cellulosic 

biofuel standard should provide an incentive for the industry to grow according to the 

goals that Congress established through EISA. However, we also believe that the 

cellulosic biofuel standard that we set should be within the range of what can be attained 

based on projected domestic production and import potential. Any estimate we use to set 

the cellulosic biofuel standard for 2011 will have some uncertainty in terms of actual 

attainment, and the level of such uncertainty generally rises with the volume mandate. 

Our intention is to balance such uncertainty with the objective of providing an incentive 

for growth in the industry. To this end, we explored the 2011 volumes for individual 

companies as projected by EIA to determine not only what volumes might be anticipated, 

but more importantly what volumes were potentially attainable. Our final projected 

available volume of cellulosic biofuel for 2011 reflects these considerations. 

Nevertheless, in the event that the biofuel industry ultimately fails to provide sufficient 

volumes to meet the 2011 standard for cellulosic biofuel, obligated parties can purchase 

waiver credits from the EPA under the provisions of §80.1456. The price for such waiver 

credits is being established in today's action in Section VI.A. 

 In addition to the sources described above, we had intended to use information 

provided through the Production Outlook Reports required under §80.1449 for all 

registered renewable fuel producers and importers. These reports were due to the Agency 

by September 1, 2010. While these reports were informative for the companies that did 

submit them, most potential cellulosic biofuel producers had not yet registered under the 

RFS program and therefore were not required to submit Production Outlook Reports. 
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Moreover, only a small percentage of the reports were both complete and correct upon 

initial submission, and about one-fourth of all registered producers and importers failed 

to submit a report. These issues are likely the result of this being the first time that such 

reports were due and remedial actions are expected to lead to a more complete set of 

valid reports later in 2010. However, the Production Outlook Reports were of limited 

value for development of the biofuel volume projections that we used to set the standards 

for 2011. 

 In our analysis, we have focused on biofuel production as required by Section 

211(o)(7)(D)(i) of the Clean Air Act. We have not considered the demand for biofuels as 

a factor in determining the appropriate volume of cellulosic biofuel to require in 2011. 

However, we note that the volumes of cellulosic biofuel that we proposed and the 

required volume we are finalizing today are very small in terms of total demand for 

biofuels, and are thus unlikely to impact issues related to demand for biofuels such as 

infrastructure for distributing or consuming biofuels. 

A. Cellulosic Biofuel 

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

2011 is challenging. Announcements of new projects, changes in project plans, project 

delays, and cancellations occur with great regularity. Biofuel producers face not only the 
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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 volumes for 2011, EPA has 

tracked the progress of over 100 cellulosic biofuel production facilities. From this large 

group of over 100 production facilities we identified 35 that had planned to begin 

cellulosic biofuel production by early 2012. From this smaller list of facilities we used 

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

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

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

contacted to provide the most up to date information possible on their current cellulosic 

biofuel production plans for 2011. Our estimate of the projected available cellulosic 

biofuel volume for 2011 is based on the information we received in conversations with 

these companies as well as our own assessment of the potential for these facilities to 

produce cellulosic biofuel in the volumes indicated. Throughout this process EPA 

engaged in discussions with EIA to share information and insights into potential 

cellulosic biofuel production in 2011. For more details on EIA’s cellulosic biofuel 

projections for 2011 and a discussion of the differences between the projections made by 

EPA and EIA see Section II.A.3. 

 A brief description of each of the companies we believe has the potential to 

produce cellulosic biofuel and make it commercially available can be found below. A 

more in-depth discussion of the technologies used to produce cellulosic biofuels can be 
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found in Section IV. Based on this information, EPA projects that 6.6 million gallons of 

cellulosic biofuel (corresponding to 6.0 million ethanol-equivalent RINs) could be 

produced and made available in 2011. This is the number we used as the basis for the 

percentage standard for 2011. The rest of this section describes the analyses that we used 

as the basis for this projected available production volume. 

 1. Domestic Cellulosic Biofuel

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

are four companies in the United States with the potential to produce cellulosic alcohol 

and make it commercially available in 2011. These companies are DuPont Danisco, 

Fiberight, KL Energy Corporation, and Range Fuels. EPA also believes that a fifth 

company, KiOR, will be in a position to produce some cellulosic diesel fuel in 2011. 

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

assessment of their potential fuel production in 2011 based on information we have 

acquired to date. 

 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. DDCE has indicated that they could 

produce up to 150,000 gallons of ethanol in 2011 from the Vonore facility. 
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 Fiberight is a company planning to convert MSW to ethanol. Fiberight purchased 

a small corn ethanol plant in Blairstown, IA and has modified it to produce ethanol from 

cellulosic biomass. They use an enzymatic hydrolysis process to convert the cellulosic 

waste materials to simple sugars and then to ethanol. Fiberight plans to initially use a 

waste cellulose stream from a paper recycling facility as their primary feedstock, and 

eventually complement that with a sorted MSW stream. Fiberight started producing 

ethanol in the summer of 2010 and plans to ramp up to full production capacity by late 

2011. Fiberight has provided month-by-month production targets for 2011 to EPA. 

Based on these targets their projected production potential for 2011 is 2.8 million gallons 

of cellulosic ethanol. While there is still some uncertainty as to whether their supply of 

waste cellulose from paper recycling meets the regulatory definition of renewable 

biomass, fuel from such feedstock would only account for about one-fifth of the total 

ethanol expected to be produced by Fiberight in 2011. Moreover, Fiberight's choice of 

feedstock for ethanol production could change depending on whether waste cellulose 

from paper recycling is determined to meet the regulatory definition of renewable 

biomass. For the purposes of projecting potentially available cellulosic volume for 2011, 

therefore, we have included in our estimates the portion that could be produced from 

waste cellulose from paper recycling 

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

ethanol in 2011 is KL Energy Corporation. KL Energy has a demonstration facility in 

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

wood waste to ethanol and has just announced a partnership with Petrobras for the 
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construction of additional facilities. The demonstration 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 of this facility they have been gradually 

ramping up production and gathering information to optimize this and future ethanol 

production facilities. While production levels from this facility have so far been below 

capacity, KL has informed EPA that they intend to produce up to 400,000 gallons of 

cellulosic ethanol from their Upton, WY facility in 2011. 

 A fourth company that EPA expects will produce cellulosic biofuel in 2011 is 

Range Fuels. Range has a facility in Soperton, Georgia capable of processing 125 dry 

tons of feedstock per day. This facility completed commissioning in the second quarter 

of 2010 and began producing cellulosic methanol in the third quarter of 2010. Range 

initially plans to use wood chips as their feedstock, but will also investigate using 

different types of woody biomass and herbaceous energy crops. In Phase I of this 

project, Range will predominantly use a commercial methanol catalyst, but they plan to 

produce some ethanol using a proprietary mixed alcohol catalyst. No approved pathway 

currently exists under the RFS program for the generation of RINs for methanol, and the 

opportunities for using methanol in the transportation fuel market are limited. However, 

Range does plan on adding capabilities in Phase II that will increase the relative 

production volume of ethanol versus methanol. Moreover, EPA is evaluating possible 

RIN-generating pathways for cellulosic methanol, including the potential for cellulosic 

methanol used in the production of biodiesel to qualify for the generation of cellulosic 

biofuel RINs. 
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 At this time EPA projects that Range Fuels will produce 0.1 million gallons of 

ethanol and 2.9 million gallons of methanol from this facility in 2011. Given a methanol 

equivalence value of 0.75, this fuel represents 2.3 million ethanol equivalent gallons. 

Based the potential for Range to produce larger proportions of ethanol, and the possibility 

that RIN-generating pathways for cellulosic methanol could be identified or approved we 

are projecting production of2.3 million gallons of RIN-generating cellulosic biofuel by 

Range Fuels in 2011. 

 

 The only company that EPA is aware of that may be a producer of cellulosic 

diesel in 2011 is KiOR. KiOR has developed a catalytic pyrolysis technology capable of 

converting cellulosic biomass directly to a bio-crude with a low oxygen content. KiOR 

currently has a small pilot facility capable of producing 10 – 15 barrels of bio-crude per 

day in Houston, Texas. In order for this fuel to be used as a transportation fuel it would 

have to go through further refining. This could either be done at the KiOR facility if the 

necessary equipment is installed, or at an existing refinery. While KiOR is not currently 

producing a finished transportation fuel, this bio-oil could be upgraded and be eligible for 

RIN generation under the RFS program. EPA projects that this facility can produce 0.2 

million gallons of fuel, representing 0.3 million RINs in 2011. 

 In the proposed rule we also discussed two other potential cellulosic diesel 

producers, Bell BioEnergy and Cello Energy. Since the publication of the proposed rule 

the project that Bell BioEnergy had been working on that EPA had identified as a 
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potential source of cellulosic biofuel has been terminated. They are currently exploring 

other options for locations for their first commercial facility, as well as potential sources 

of funding. While we are not counting on any volume from Bell BioEnergy for the 2011 

projected available volume, it is feasible that they could produce cellulosic diesel or jet 

fuel in 2011 if they are able to identify a suitable location for their facility and secure the 

necessary funding in the near future. 

The other cellulosic diesel company discussed in the proposed rule is Cello 

Energy. Cello has a structurally complete facility in Bay Minette, Alabama with an 

annual production capacity of 20 million gallons of diesel per year. While their facility is 

structurally complete, they have experienced feedstock preparation and handling issues 

that need to be resolved before they will be able to again attempt start up and production. 

Litigation related to contract issues has also provided a set-back likely delaying any 

potential production from Cello’s facility. On October 20, 2010 Cello Energy filed for 

Chapter 11 bankruptcy, therefore no volume from this facility has been included in our 

projected cellulosic biofuel volume for 2011. 

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

producing cellulosic biofuel other than ethanol, methanol, and diesel and making it 

commercially available in 2011. EPA is currently tracking the efforts of 10 companies 

that plan to produce fuels such as butanol, 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 
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cellulosic fuel commercially available until 2012 at the earliest. There are several 

companies with small demonstration facilities who intend to produce biofuels 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 have not counted these potential volumes in our 

projections for 2011. 

 2. Imports of Cellulosic Biofuel

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

three companies located in other countries with the potential for cellulosic biofuel 

production in 2011. If this fuel is produced with renewable biomass and imported into 

the United States for use in transportation fuel, jet fuel, or heating oil, it would be eligible 

to participate in the RFS2 program. However, for the reasons described below, we have 

not included any imported cellulosic biofuel in our projections of available U.S. volume 

for 2011. 

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

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

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

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

volumes of ethanol since 2004. So far all of the ethanol produced by this facility has 
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been used locally and in racing and other promotional events. In conversations with EPA 

Iogen has indicated that they do not intend to export any fuel to the United States from 

this facility in 2011. 

 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 methanol and ethanol. Enerkem finished construction on a 1.3 million gallon per 

year facility in Westbury, Quebec in June 2010 and plans to begin producing methanol 

and ethanol later in 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 their products locally, and do not 

intend any exports to the United States. 

 A third international company that may produce commercial volumes of 

cellulosic biofuel in 2011 is Choren. Choren has completed construction of a facility in 

Freiberg, Germany with a production capacity of 3.9 million gallons of diesel fuel. This 

facility used a thermochemical process to convert biomass to syngas and then 

catalytically converts the syngas to diesel fuel. The facility is currently undergoing 

commissioning and it is unclear when they will begin commercial production. 

Additionally, there is likely to be strong local demand for the fuel. Due to these factors, 

EPA is not projecting that any fuel produced by Choren will be imported into the U.S. in 

2011. 
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 While these facilities appear to be the most likely sources of imported cellulosic 

biofuel, it is possible that cellulosic biofuels produced by other foreign companies may be 

imported into the United States. One strong candidate as a 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 planning commercial 

scale production of cellulosic biofuel in Brazil. It is unlikely these projects will be 

completed in time to supply cellulosic biofuel to the United States in 2011; however they 

may be a significant source of cellulosic biofuel imports in future years. 

 3. Projections from the Energy Information Administration

 Section 211(o)(3)(A) of the Clean Air Act requires EIA to "...provide to the 

Administrator of the Environmental Protection Agency an estimate, with respect to the 

following calendar year, of the volumes of transportation fuel, biomass-based diesel, and 

cellulosic biofuel projected to be sold or introduced into commerce in the United States." 

EIA provided these estimates to us on October 20, 2010.4 With regard to cellulosic 

biofuel, the EIA estimated that the available volume in 2011 would be 3.94 mill gallons 

based on their assessment of the utilization of production capacity. A summary of the 

plants they considered is shown below in Table II.A.3-1. 

 

4

 Letter from Richard Newell, EIA Administrator to Lisa Jackson, EPA Administrator October 20, 2010. 
 Page 34 of 182

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Table II.A.3-1 

EIA’s Projected Cellulosic Biofuel Plant Production Estimates for 2011 

Company Name Location Feedstock Fuel Capacity 

(MGY) 

Facility 

Status 

Utilization 

Expected 2011 

Production 

(MG) 

DuPont Danisco Vonore, TN Corn cobs, then 

switchgrass 

Ethanol 0.25 Online 10% 0.03 

Fiberight Blairstown, 

IA 

MSW Ethanol 6.0 Online 46% 2.76 

Range Soperton, GA Wood Waste Methanol, KL Energy Upton, WY Wood Ethanol 1.5 Online 10% 0.15 

Ethanol 

4 Online 25% 1.0 

Total 3.94
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 While EIA’s projected cellulosic biofuel production estimate for 2011 is, with the 

exception of KiOR, based on an evaluation of the same companies that EPA evaluated, 

the production volume assumed by EIA for each company is lower in all cases. We 

believe that the difference reflects EIA's intention to estimate volumes that each company 

has a high certainty of reaching in 2011. As described in Section II.A above, we have 

projected the volume of cellulosic biofuel that we believe is attainable given the issues 

that each company faces, while recognizing that there is some uncertainty in the projected 

volumes. We believe that many or all of the uncertainties associated with the potential 

volume production at each company can be resolved in a positive direction. 

We have considered EIA’s projection of cellulosic biofuel production for 2011 in 

the context of setting the 2011 cellulosic biofuel standard, and we believe that it 

represents a volume that the industry is unlikely to fall below. However, we believe that 

it is appropriate to set the applicable volume at a level that provides an incentive for 

developing cellulosic biofuel facilities to come on line as expeditiously as possible, and 

to provide reasonable assurance that there will be a market for their product if they do. 

Moreover, we also believe that CAA 211(o)(7)(D) is best interpreted to vest the authority 

for making the projection with EPA, since it provides that the projection is “determined 

by the Administrator based on the estimate provided [by EIA].” If Congress intended 

that EPA simply adopt EIA’s projection without an independent evaluation, it would not 

have specified that the projection is “determined” by EPA. Although the statute provides 
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that our determination must be “based on the estimate provided” by EIA, we believe that 

our consideration of EIA’s estimate in deriving our own projection satisfies this statutory 

requirement. For the reasons described above, we believe that EPA’s projection takes 

into account uncertainties in a manner that best furthers the objectives of the statute. 

4. Overall 2011 Volume Projections

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

2011, summarized above, allows us to project the potential production volume of each 

facility in 2011. After the appropriate equivalence value has been applied to the volumes 

from these facilities, the overall projected ethanol-equivalent volume of cellulosic biofuel 

for 2011 can be totaled. This information is summarized in Table II.A.4-1 below. 
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Table II.A.4-1 

Projected Potential Volume of Cellulosic Biofuel Production in 2011 

Company Name Location Feedstock Fuel Capacity 

(MGY) 

Facility 

Status 

Projected 

Potential Volume 

(MG) 

Ethanol 

Equivalent 

Gallons 

(MG) 

DuPont Danisco Vonore, TN Corn cobs, then 

switchgrass 

Ethanol 0.25 Online 0.15 0.15 

Fiberight Blairstown, 

IA 

MSW Ethanol 6 Online 2.8 2.8 

Range Soperton, GA Wood Waste Methanol, KiOR Houston, TX Wood Waste Diesel 0.2 Online 0.2 0.3 KL Energy Upton, WY Wood Ethanol 1.5 Online 0.4 0.4 

Ethanol 

4 Online 3.0 2.3 

Total 6.6 6.0
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 While the production volumes in Table II.A.4-1 have some uncertainty, we 

believe that a total volume of 6.0 million gallons is attainable. By basing the 2011 

cellulosic biofuel standard on the attainable volumes rather than discounting projected 

volumes to account for uncertainty, we aim to avoid the undesirable scenario in which 

cellulosic biofuel production exceeds the mandated volume. Such a scenario would 

result in weak demand for cellulosic biofuels and RINs. Additionally, while obligated 

parties are able to purchase cellulosic biofuel waivers credits in the event that production 

of cellulosic biofuel is insufficient to meet the 2011 standard, no mechanism exists for 

this standard to be raised should cellulosic biofuel production exceed the 2011 standard. 

The intent of Congress in establishing the RFS program through EISA was to provide a 

reliable market for renewable fuels and in doing so to spur growth in the cellulosic 

biofuels industry. EPA believes the projected available volume finalized in this rule best 

reflects these intentions. 

 Three commenters (Abengoa, Growth Energy, and Unica) supported the range of 

6.5 - 25.5 million gallons that EPA proposed in the NPRM. The Biotechnology Industry 

Organization and Dupont Danisco Cellulosic Ethanol commented that the EPA’s 

proposed range was a reasonable estimate, but encouraged EPA to consider ways the RFS 

program can serve a risk mitigation function for the cellulosic biofuel industry. Two 

commenters, American Petroleum Institute and National Petrochemical & Refiners 

Association, suggested that EPA consider only companies that have demonstrated, 

proven production records when setting the cellulosic standard for the following year. 

The Low Carbon Synthetic Fuels Association suggested EPA set the standard high 
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enough so that any cellulosic biofuel that might be produced in 2011 in the US or 

internationally would be included in the volume projections. They suggest that this 

would mean using the high end of the proposed volume, or even some volume above the 

proposed range. 

 Based on our assessment of the potential production capabilities of individual 

companies as described above, EPA is finalizing the cellulosic biofuel standard for 2011 

at 6.0 million ethanol-equivalent gallons of cellulosic biofuel. This number represents 

the volume of RIN-generating cellulosic biofuel that we believe can be 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 fuel 

production can begin and assumptions regarding a ramp-up period to full production. We 

believe that a production volume of 6.0 mill gal is attainable despite the uncertainties, 

since none of the possible impediments to attaining this volume appear insurmountable. 

Moreover, by setting the standard for cellulosic biofuel based on the volumes that are 

attainable, we are providing greater incentives for producers to overcome uncertainties 

and greater opportunities for funding based on an established demand. 

 There are also a variety of factors that could lead to production volumes greater 

than those listed in Table II.A.4-1 and make up for potential shortfalls elsewhere. For 

instance: 
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• For each of the facilities listed, with the exception of KiOR, we are projecting that 

their production will be some volume less than the capacity of their facility. It is 

possible, however, that these companies could produce a greater volume of fuel 

than they are currently anticipating or has been projected by EPA. 

• It is possible that companies that are currently targeting 2012 for commercial 

production may produce cellulosic biofuel ahead of schedule and generate RINs 

in 2011. None of this volume was included in our projection for 2011. 

• A high demand for cellulosic biofuels may be sufficient to cause companies to 

import fuel into the United States, even if they currently have no plans to do so. 

As described in Section II.A.2 above, there are several foreign producers that are 

either producing cellulosic biofuel now, or could potentially produce some 

cellulosic biofuel volume in 2011. 

 Finally, we note that if the actual volume of cellulosic biofuel RINs that are 

available in 2011 falls short of the 6.0 million gallon RINs used to derive the 2011 

cellulosic biofuel standard, obligated parties have other recourses: 

• Purchase cellulosic biofuel waiver credits from the EPA (see further discussion in 

Section VI.A) 

• Carry over a deficit from 2011 into 2012 according to §80.1427(b) 
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 5. Projections of Cellulosic Biofuel for 2012

 In addition to the companies discussed above, EPA also assessed the production 

capabilities of many other companies to determine their ability to produce cellulosic 

ethanol in 2011. Many of these companies had at some point planned to produce 

cellulosic ethanol at commercial scale by 2011, but due to a variety of factors have had 

their plans delayed. Despite these delays, the outlook for 2012 and later years still looks 

promising. 

Although the cellulosic biofuel standard we are setting for 2011 is considerably 

below the applicable volumes established in EISA, EPA believes there is reason for 

optimism when looking at the plans for the cellulosic biofuel industry in 2012 and 

beyond. EPA is currently aware of more than 20 facilities representing over 300 million 

gallons of production that are targeting commercial production of cellulosic biofuels in 

2012. Many companies, including Abengoa, AE Biofuels, BlueFire Ethanol, Coskata, 

Fulcrum, POET, and Vercipia, are intending to begin bringing large scale facilities 

online, with physical capacities of between 10 and 100 million gallons of cellulosic 

biofuel per year. There is also hope within the industry that as these first-of-a-kind 

technologies prove commercially viable that new financing opportunities will open up for 

both new facilities and facility expansion alike. This could lead to rapid growth in the 

cellulosic biofuel industry as many companies, in addition to those mentioned above, 
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have announced project plans that have been put on hold until funding or project partners 

can be found. 

B. Advanced Biofuel and Total Renewable Fuel 

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

volumes of advanced biofuel and total renewable fuel in the event that the projected 

volume of cellulosic biofuel production is determined to be below the applicable volume 

specified in the statute. As described in Section II.A above, we are indeed projecting the 

volume of cellulosic biofuel production for 2011 at significantly below the statutory 

applicable volume of 250 million gallons. Therefore, we must consider whether and to 

what degree to lower the advanced biofuel and total renewable fuel applicable volumes 

for 2011. 

 As described in the NPRM, because cellulosic biofuel is used to satisfy both the 

cellulosic biofuel standard and the advanced biofuel standard, it is possible that a required 

volume of cellulosic biofuel for a given year that is less than the volume specified in the 

statute could lead to a situation where there is insufficient volume of advanced biofuels to 

satisfy the applicable volume of advanced biofuel volume set forth in the statute. 

However, it is also possible that other advanced biofuels, such biomass-based diesel, 

sugarcane ethanol, or other biofuels, may be available in sufficient volumes to make up 

for the shortfall in cellulosic biofuel. We believe that it would be consistent with the 
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energy security and greenhouse gas reduction goals of EISA to use the applicable volume 

of advanced biofuel set forth in the statute to derive the advanced biofuel standard if there 

are sufficient volumes of advanced biofuels available, even if those volumes do not 

include the amount of cellulosic biofuel that Congress may have desired. 

 If we were to maintain the advanced biofuel, biomass-based diesel, and total 

renewable fuel volume requirements at the levels specified in the statute, while also 

lowering the cellulosic biofuel standard to 6.0 million gallons, then 1206 million gallons 

of the 1350 million gallon advanced biofuel mandate would be satisfied automatically 

through the satisfaction of the cellulosic and biomass based diesel standards. An 

additional 144 million ethanol-equivalent gallons of additional advanced biofuels would 

be needed. See Table II.B-1. 
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Table II.B-1 

Projected Fuel Mix If Only Cellulosic Biofuel Volume is Adjusted in 2011 (mill gallons) 

 Ethanol-Equivalent 

Volume 

Physical Volume 

Total renewable fuel 

Conventional renewable fuela

13,950 

12,600 

13,500 - 13,549 

12,600 

Total advanced biofuel 1,350 903 - 951 

Cellulosic biofuel 

Biomass-based diesel 

Other advanced biofuelb

6.0 

1200 

144 

6.6 

800 

96 - 144c

a

 Predominantly corn-starch ethanol

b

 Rounded to nearest million gallons for simplicity 

c Physical volume is a range because other advanced biofuel may be ethanol, biodiesel, 

or some combination of the two 

 The most likely sources of additional advanced biofuel would be imported 

sugarcane ethanol and biodiesel. To determine if there are likely to be sufficient volumes 

of these biofuels to meet the need for 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.B-2 below, recent annual import volumes of ethanol were higher 

than what would be needed in 2011. 
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Table II.B-2 

Historical Imports of Ethanol (mill gallons)5

2007 

2008 

2009 

439 

530 

194 

Brazilian imports have made up a sizeable portion of total ethanol imported into the U.S. 

in the past, and these volumes were predominantly produced from sugarcane. These 

historical import volumes demonstrate that Brazil has significant export potential under 

the appropriate economic circumstances. However, as shown above, ethanol import 

volumes decreased significantly in 2009. Moreover, they have dropped to nearly zero in 

the first half of 2010 according to EIA's Short Term Energy Outlook. Some have 

speculated that this decline in imports is related to the cessation of the duty drawback that 

became effective on October 1, 2008,and to changes in world sugar prices.6

 However, 

Brazil is second worldwide in the production of ethanol, reaching about 6.5 billion 

gallons in 2008.7 Thus, by establishing an increased U.S. demand for 144 million gallons 

of other advanced biofuel in 2011, we believe it may once again be economical for 

Brazilian producers to export at least this volume of sugarcane ethanol to the U.S. 

Moreover, 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. 

 

5

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

6

 Lundell, Drake, “Brazilian Ethanol Export Surge to End; U.S. Customs Loophole Closed Oct. 1,” Ethanol 

and Biodiesel News, Issue 45, November 4, 2008. 

7

 Renewable Fuels Association (RFA), “2008 World Fuel Ethanol Production, ” 

http://www.ethanolrfa.org/pages/statistics#E, March 31, 2009. 
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 We also examined the potential for excess biodiesel to help meet the need for 144 

million gallons of advanced biofuel. The applicable volume of biomass based diesel 

established in the statute for 2011 is 800 million gallons (which corresponds to 1200 

ethanol equivalent gallons). As discussed more fully in Section II.C below, we believe 

that the biodiesel industry has the potential for producing significant volumes above 800 

million gallons if demand for such volume exists.. 

 Finally, there are also other potential sources of advanced biofuels that could 

contribute to compliance with the advanced biofuels standard in 2011, such as diesel fuel 

additives made from waste cooking oil or restaurant grease. Given all of these potential 

sources, we believe that there are likely to be sufficient volumes of advanced biofuels 

such that the advanced biofuel standard need not be lowered below the 1.35 billion gallon 

level specified in the Act. Thus, we are not reducing the applicable volume of advanced 

biofuel for 2011. 

 If we were reducing the applicable volume of advanced biofuel for 2011, it would 

follow that there could be a shortfall of RINs capable of satisfying the general renewable 

fuel volume requirements. However, we are not doing so, and thus there is no need to 

lower the applicable volume of total renewable fuel below the statutory volume of 13.95 

billion gallons. 
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 In response to the NPRM, biodiesel producers, advanced biofuel producers, and 

UNICA (representing importers of sugarcane ethanol) supported our proposal to maintain 

the applicable volume of advanced biofuel at 1.35 bill gallons for 2011. They generally 

agreed that there exists sufficient potential sources of advanced biofuel to make up for the 

reduction of the applicable volume of cellulosic biofuel for 2011, and that the very 

existence of a demand for this volume will lead these sources to provide sufficient 

volume to meet that demand. Other commenters, such as refiners and proponents of 

corn-ethanol, opposed our proposal for leaving the 2011 applicable volume of advanced 

biofuel at 1.35 bill gallons on the grounds that other sources of advanced biofuel 

sufficient to make up for the reduction in the applicable volume of cellulosic biofuel 

were too uncertain. 

 We disagree with the suggestion that volumes of other advanced biofuels are too 

uncertain and that the applicable volume of advanced biofuel should be lowered. As 

described above, we believe that there are sufficient potential sources of other advanced 

biofuel to make up for the reduction in the applicable volume of cellulosic biofuel. 

Moreover, our authority to lower the advanced biofuel and/or total renewable fuel 

applicable volumes is discretionary, and we believe that actions to lower these volumes 

should only be taken if it appears that insufficient volumes of qualifying biofuel can be 

made available, based on such circumstances as insufficient production capacity, 

insufficient feedstocks, competing markets, constrained infrastructure, or the like. Since 

this is not the case for 2011, we do not believe that the advanced biofuel applicable 
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volume of 1.35 bill gallons or the total renewable fuel applicable volume of 13.95 billion 

gallons should be reduced. 

 Although refiners and proponents of corn-ethanol agreed on the treatment of 

advanced biofuel for 2011, they differed in their views of how the total renewable fuel 

standard should be treated. Refiners stated that the advanced biofuel standard and the 

total renewable fuel standard should be lowered in concert and by the same amount. 

Proponents of corn-ethanol, on the other hand, stated that the total renewable fuel 

standard of 13.95 bill gal should be maintained while the advanced biofuel standard 

should be lowered to reflect the projected shortfall. They argued that excess volumes of 

corn-ethanol were more certain than excess volumes of advanced biofuel, and that their 

suggested approach would effectively result in a demand for corn-ethanol above 12.6 

billion gallons (see Table II.B-1). They further argued that this approach would generate 

more GHG reductions than if the advanced biofuel and total renewable fuel standards 

were lowered in concert. One commenter explicitly opposed any changes to the 

advanced biofuel and total renewable fuel standards that would increase the demand for 

corn-ethanol under RFS2 above 12.6 billion gallons (see Table II.B-1). 

 We agree that there is sufficient corn-ethanol production capacity and feedstocks 

to produce more than 12.6 bill gallons in 2011. Indeed EIA projects that corn-ethanol 

production in 2010 will exceed 13 billion gallons.8

 However, as described above, we 

disagree with the suggestion that there is insufficient volume of advanced biofuels to 

justify maintaining the advanced biofuel applicable volume at the level specified in the 

 

8

 EIA STEO, September 2010, Table 8 
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statute. Moreover, since there is no need to waive any portion of the advanced biofuel 

applicable volume, there is likewise no need to consider the possibility of corn ethanol 

making up for a shortfall in advanced biofuel volumes. As a result, the demand for corn 

ethanol will not be greater as a result of today’s action than it would be if all applicable 

volumes as specified in the statute were used in deriving the 2011 standards. 

C. 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, we must, as discussed above, 

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 directly 

affects our consideration of adjustments to the volumetric requirements for advanced 

biofuel and total renewable fuel discussed above in Section II.B. 

 Although there are a variety of potential fuel types that can qualify as biomassbased diesel, biodiesel is by far the predominant type. To project biodiesel production 

volumes for 2011, we examined historical and recent production and export rates as well 

as the production potential of the industry. As shown in Table II.C-1, domestic 

production of biodiesel in 2007-2009 has ranged from 490 to 678 million gallons. 
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Table II.C-1 

Historical Biodiesel Production, Net Exports, and Consumption (million gallons) 

(Source: EIA Monthly Energy Review, August 2010) 

 Domestic 

Production Net Exports 

Domestic 

Consumption 

2007 490 132 358 

2008 678 362 316 

2009 505 189 315 

The variations in production and net exports appear to be correlated to availability of the 

U.S. tax subsidy that was effective from 2004 to 2009, "splash-and-dash" activities, and 

European Union (EU) action to impose duties on exported U.S. biodiesel.. In splash-anddash, biodiesel producers took advantage of the U.S. tax credit for biodiesel even though 

the biodiesel was not consumed in the U.S., instead exporting the biodiesel to Europe. 

As can be seen in Figure II.C-1, the EU took action beginning in March 2009 to apply 

duties/tariffs to biodiesel from the U.S. Exports of biodiesel from the U.S., as well as 

domestic production volumes, immediately fell following this EU action. Production 

also fell following the expiration of the biodiesel tax credit at the end of 2009. 
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Figure II.C-1 

Monthly Biodiesel Production and Net Exports (million gallons) 

(Source: EIA Monthly Energy Review, August 2010) 

-20-10

0

1020304050607080

J FMAMJ J ASOND J FMAMJ J ASO ND J FMAMJ J A SOND J F MAM

Million gallons per month

Production Net exports

2007 2008 2009 2010

EU applies duties 

to U.S. biodiesel

U.S. tax 

credit ends
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Although biodiesel production appears to have been significantly affected by both the EU 

tariff on biodiesel from the U.S. and the expiration of the biodiesel tax credit, the fact that 

the U.S. biodiesel industry has produced higher volumes when it was economic for it to 

do so suggests that the industry may have the capability to produce greater volumes in the 

future under the appropriate circumstances. According to information from the biodiesel 

industry, only 52 biodiesel facilities with a production capacity totalling 600 million 

gallons have been idled. The total biodiesel production capacity at facilities that are still 

operating is 2.4 billion gallons9

. Ramping up production will require some time and 

potentially some reinvestment, but based on feedback from industry we nevertheless 

believe that it can occur in time to meet a production goal of 800 million gallons. 

 In response to the NPRM, some commenters suggested that the 2011 volume 

requirement for biomass-based diesel should be lowered because the biodiesel industry is 

expected to produce insufficient volumes in 2010 to meet the 2009/2010 biomass-based 

diesel standard based on an applicable volume of 1.15 billion gallons. This, they argued, 

demonstrates that the biodiesel industry cannot be expected to meet demand of 800 

million gallons in 2011. However, for the first five months of 2010, the average 

production rate was about 32 million gallons per month.10 If this production rate 

continued through the rest of 2010, the total annual production of biodiesel would be 

approximately 380 million gallons. As described in EPA's Question and Answer 

document11, EPA estimated that the 1.15 bill gal standard for biomass-based diesel in 

 

9

 Plant List from Biodiesel Magazine (http://www.biodieselmagazine.com/plant-list.jsp) 

10 EIA Monthly Energy Review for August 2010, Table 10.4. 

11 See question 6.7 in EPA's "Questions and Answers on Changes to the Renewable Fuel Standard Program 

(RFS2)", http://www.epa.gov/otaq/fuels/renewablefuels/compliancehelp/rfs2-aq.htm#6 
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2010 would generate a demand for about 345 mill gallons of qualifying biodiesel and 

renewable diesel in 2010. The remaining portion of the 1.15 bill gal standard would be 

met with previous-year RINs. Thus, an annual production volume of 380 million gallons 

should be sufficient to enable obligated parties to meet the 2010 biomass-based diesel 

standard if exports are kept to a minimum. In fact net exports of biodiesel have gone 

down every year since 2008, due in part to fewer cost-effective opportunities for sale of 

biodiesel in Europe. 

 Moreover, we do not believe that the activities of the biodiesel industry in 2009 

and 2010 are necessarily an appropriate indicator of its potential for 2011. A regulatory 

mandate for biomass-based diesel did not exist in 2009, and the mandate for biomassbased diesel in 2010 was a unique circumstance that allowed a significant number of 

2008 and 2009 biodiesel RINs to be used for compliance in 2010. Current biodiesel 

production rates actually suggest that the industry is positioned to put idled capacity into 

production when demand for greater volumes exist. For instance, despite the expiration 

of the biodiesel tax credit at the end of 2009, monthly domestic consumption of biodiesel 

was actually higher in the first 5 months of 2010 than it was during the same period in 

2009. One possible reason for this is that 2010 was the first year that the biomass-based 

diesel standard was in effect. Moreover, for the three years prior to 2010, the monthly 

average production in the second half of the year was higher than in the first half of the 

year. Thus, although the annual production total for 2010 would be projected to be 380 

mill gal based on monthly production rates between January and May, it could be 500 

million gallons or more by year's end if production rates increase in the second half of the 
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year as they have done in the past. An increase in monthly biodiesel production rates 

later in 2010 would also be consistent with the fact that obligated parties are not required 

to demonstrate compliance with the 2010 biomass-based diesel standard until February 

28, 2011. Thus, the presence of a requirement for biomass-based diesel in 2010 seems to 

be providing the incentive for greater consumption of biodiesel, which in turn is 

encouraging higher production volumes. 

 In addition to current production rates, the biodiesel industry's production 

potential also supports a finding that it can more than satisfy the applicable volume of 

biomass based diesel specified in the statute for 2011. In July of 2010, over 1.8 billion 

gallons of production capacity had been registered under the RFS2 program.12 As of 

September 2010, the aggregate production capacity of biodiesel plants in the U.S. was 

estimated at 2.6 billion gallons per year across approximately 170 facilities. 13 

Indications from the biodiesel industry are that idled facilities can be brought back into 

production with a relatively short leadtime. Imports of biodiesel from foreign countries 

also has the potential to increase the volume available for consumption in the U.S. 

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

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

sources of feedstock for biodiesel in 2011 are expected to be soy oil, canola oil, rendered 

fats, and potentially some corn oil extracted during production of fuel ethanol, as this 

 

12 Comments from National Biodiesel Board on the July 20, 2010 NPRM. Submitted to docket EPA-HQOAR-2010-0133 on August 19, 2010. 

13 Figures taken from National Biodiesel Board's Member Plant List as of September 13, 2010. 

http://biodiesel.org/buyingbiodiesel/plants/showall.aspx 
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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. 14

 In order to meet a 2011 biomass-based diesel volume requirement of 800 million 

gallons to be consumed in the United States, approximately 725 million gal of biodiesel 

would need to be consumed. 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 by 2011.15 Assuming net exports continue at a rate equivalent to that in the 

first five months of 2010, biodiesel production in the U.S. would need to total 

approximately 835 million gal in 2011. Based on the modeling used by EIA to project 

volumes for its Short-Term Energy Outlook, EIA projects that the 800 mill gallon 

mandate would be binding, and that this level of consumption would be unlikely to occur 

in the absence of a mandate. However, the biodiesel industry has demonstrated that it is 

capable of meeting historic demand for biodiesel, and is in a position to produce 

significantly more than it has in recent years. 

Based on our review of current biodiesel production rates, the production 

potential of the biodiesel industry, and the availability of qualifying feedstocks, we 

believe that substantially more than the 800 million gallons needed to satisfy the biomass 

based diesel standard can be produced in 2011. Today’s rule therefore includes a final 

 

14 See Federal Register v.74 n.99 p.24903. Comments are available in docket EPA-HQ-OAR-2005-0161. 

15 Project status updates are available via the Syntroleum website, http://dynamicfuelsllc.com/wp-news/ 
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biomass-based diesel standard that, as proposed, is based on the 800 million gallon 

applicable volume specified in the Act. We also believe that the excess production 

capacity can be utilized to help satisfy the 2011 advanced biofuel standard we are 

finalizing today. 

 In response to the NPRM, several parties supported our proposal to set the 2011 

standard based on the 800 million gallon applicable volume specified in the Act. One 

party requested that we raise the biomass-based diesel standard for 2011 above the 800 

million gallon statutory mandate based on the significantly higher production capacity in 

the industry. However, the statute specifies the applicable volumes of biomass based 

diesel that we are to use in setting the annual standards through 2012. We do not have 

the authority to raise the applicable volume above the level specified in the statute for 

2011. 

 Another commenter requested that the standard for biomass-based diesel should 

be tied to the biodiesel tax credit and projections of likely consumption in 2011 assuming 

no mandate. We disagree. Demand for biomass-based diesel will be a function of the 

RFS standard we set for 2011. The authority provided under CAA 211(o)(7)(A) to waive 

any portion of the statutory biomass-based diesel volume mandate is limited to cases in 

which we determine that the mandate would severely harm the economy or environment, 

or that there is inadequate domestic supply. Under CAA 211(o)(7)(E) we may also order 

a reduction in required use of biomass based diesel if we find that there is a significant 

renewable feedstock disruption or other market circumstances that would make the price 
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of biomass-based diesel fuel increase significantly. No commenter has suggested that 

any of these conditions exist. The expiration of the biodiesel tax credit is, by itself, an 

insufficient basis for a waiver, and we do not have the authority to waive a portion of the 

standard based on projections of what demand would be in the absence of a mandate. 
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III. Percentage Standards for 2011 

A. Background 

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

each obligated party 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.4, the cellulosic biofuel volume requirement for 2011 

is 6.6 million gallons (6.0 million ethanol equivalent gallons). This volume is used as the 

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

decided that the advanced biofuel and total renewable fuel volumes will not be reduced 

below the volumes set forth in the statute. The 2011 volumes used to determine the four 

percentage standards are shown in Table III.A-1. 
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Table III.A-1 

Volume Requirements for 2011 

Actual Volume 

Ethanol Equivalent 

Volume 

Cellulosic biofuel 6.6 mill gal 6.0 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 

 

 

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): 

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

= ×

( ) ( ) ( ) ( )

RFV Std 100% CB, i

CB, i

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

× = ×

( ) ( ) ( ) ( )

RFV 1.5 Std 100% BBD, i 

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

= ×

( ) ( ) ( ) ( )

RFV Std 100% AB, i

AB, i

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

= ×

( ) ( ) ( ) ( )

RFV Std 100% RF, i

RF, i

Where 

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

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

percent. 

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

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

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

Clean Air Act for year i, in gallons.

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

Clean Air Act for year i, in gallons. 
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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 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. 
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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 in part on the 49-

state gasoline and diesel consumption volumes projected by EIA. The projected volumes 
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of gasoline, ethanol, and biodiesel used to calculate the final percentage standards are 

provided by the EIA's Short-Term Energy Outlook (STEO), while the projected volume 

of transportation diesel used to calculate the final percentage standards is provided by the 

most recent Annual Energy Outlook (AEO). In the proposal, we used the March 2010 

issue of STEO and the Early Release version of AEO2010. For this final rule, we have 

used the volumes of transportation fuel provided by EIA under CAA 211(o)(3)(A) in a 

letter dated October 20, 201016 This letter aggregates volume projections from several 

EIA sources including the most recently available versions of STEO and AEO. Gasoline 

and diesel volumes are adjusted in the formulas to account for renewable fuel contained 

in the STEO and AEO projections. Beginning in 2011, gasoline and diesel volumes 

produced by small refineries and small refiners will generally no longer be exempt, and 

thus there is no adjustment to the gasoline and diesel volumes in today's final rule to 

account for such an exemption. 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 some small refineries could be extended. In addition, we 

may extend the exemption for individual small refineries on a case-by-case basis if they 

demonstrate disproportionate economic hardship. If any small refinery exemptions for 

2011 are approved after this final rulemaking, the parties in question would be exempt 

but we would not intend to modify the applicable percentage standards and announce 

new standards for 2011. EPA believes the Act is best interpreted to require issuance of a 

single annual standard in November that is applicable in the following calendar year, 

thereby providing advance notice and certainty to obligated parties regarding their 

regulatory requirements. Periodic revisions to the standards to reflect waivers issued to 

 

16 Letter from Richard Newell, EIA Administrator to Lisa Jackson, EPA Administrator. 
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small refineries or refiners would be inconsistent with the statutory text, and would 

introduce an undesirable level of uncertainty for obligated parties. 

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

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

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

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

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

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

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

provides that the required volume be multiplied by 1.5 under the assumption that 

biodiesel will predominate the biomass-based diesel market. The net result is that a 

physical gallon of biodiesel will be 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. 
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 Note that the equation’s terms for projected volumes of gasoline and diesel use 

include gasoline and diesel that has been blended with renewable fuel. In the equation, 

the total renewable fuel volume is subtracted from the total gasoline and diesel volume to 

get total non-renewable gasoline and diesel volumes (because the gasoline and diesel 

volumes provided by EIA include renewable fuel use), The values of the equation 

variables for 2011 are shown in Table III.B.1-1.17 Terms not included in this table have a 

value of zero. 

Table III.B.1-1 

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

Term Value 

RFVCB,2011 0.006 

RFVBBD,2011 0.80 

RFVAB,2011 1.35 

RFVRF,2011 13.95 

G2011 139.07 

D2011 49.21 

RG2011 13.45 

RD2011 0.71 

 

17 To determine the 49-state values for gasoline and diesel, the amounts of these fuels used in Alaska is 

subtracted from the totals provided by DOE. The Alaska fractions are determined from the most recent 

(2008) EIA State Energy Data, Transportation Sector Energy Consumption Estimates. The gasoline and 

distillate fuel oil fractions are approximately 0.2% and 0.7%, respectively. Ethanol use in Alaska is 

estimated at 5% of its gasoline consumption (based on the same State data), and biodiesel use is assumed to 

be zero. 
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Using the volumes shown in Table III.B.1-1, we have calculated the percentage 

standards for 2011 as shown in Table III.B.1-2. 

Table III.B.1-2 

 Percentage Standards for 2011 

Cellulosic biofuel 0.003% 

Biomass-based diesel 0.69% 

Advanced biofuel 0.78% 

Renewable fuel 8.01% 

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 
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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 

§80.1441. 

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

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

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

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

other is based on EPA evaluation of claims of disproportionate economic hardship, the 

DOE study, and other economic factors on a case-by-case basis in response to small 

refinery 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; 

DOE further noted that, if the RIN market were to change, individual refineries still have 

a statutory right to apply for relief on a case-by-case basis. Subsequently, the Senate 

Appropriations Committee “directed [DOE] to reopen and reassess the Small Refineries 

Exemption Study by June 30, 2010,” listing a number of factors that the Committee 

intended DOE to consider in the revised study. The Final Conference Report to the 

Energy & Water Development Appropriations Act added that the conferees “support the 

study requested by the Senate on RFS and expect the Department to undertake the 

requested economic review.” DOE was directed to complete a reassessment and issue a 
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revised report by June 30, 2010. A revised study had not been issued at the time of the 

RFS2 final rulemaking, or at the time of this writing. 

We have received three petitions from small refineries requesting an extension of 

their exemption from the RFS2 requirements. In evaluating these petitions, EISA 

requires that EPA "...consider the findings of the [DOE] study ... and other economic 

factors." Although the DOE study issued in January 2009 would satisfy the statutory 

requirement that we consider the DOE study before acting, we believe that our evaluation 

of these three petitions will be better informed if we consider the findings of the 

forthcoming revised DOE study. Since the revised study is not yet available, we have 

assumed that all small refineries and small refiners will be subject to the RFS2 standards 

in 2011 for the purposes of calculating those standards. If, subsequent to announcing the 

2011 standards, we make a determination that one or more hardship petitions should be 

approved, we do not intend to revise the 2011 standards applicable to other obligated 

parties to require that they make up for volumes that will not be attained by the exempt 

refineries. 

We received only three comments on the treatment of small refineries in the RFS2 

program, and all supported the inclusion of small refineries and small refiners as 

obligated parties beginning in 2011. API additionally requested that any consideration of 

extending the exemption for any small refinery into 2011 also take into account the 

impact that such an action would have on other refineries, specifically with regard to the 

ethanol blendwall. However, we do not believe that the extension of any small refinery 
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exemptions into 2011 will have a significant impact on the ethanol blendwall. Since the 

total volume of renewable fuel required under RFS2 is the same regardless of whether 

any small refineries are exempt or not, such exemptions will have no impact on the 

relative volumes of ethanol and gasoline in the nationwide transportation fuels market. 

Thus, the timing of the onset of the nationwide blendwall will not be affected by any 

small refinery exemptions. We do recognize that any exemption for a small refinery will 

result in a proportionally higher percentage standard for remaining obligated parties, and 

that this will affect the degree to which individual obligated parties can acquire sufficient 

RINs for compliance through blending ethanol into gasoline that they produce. This may 

be of particular concern to obligated parties whose gasoline production volume is higher 

than the volume of gasoline that they market, since such parties may have fewer 

opportunities to blend renewable fuels into their own gasoline and diesel. In such cases, 

obligated parties also have the option of marketing E85 for use in FFVs, extending their 

operations to include more gasoline marketing, or purchasing RINs on the open market. 
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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 Currently Valid for the Production of Cellulosic 

Biofuel? 

 In determining the appropriate volume of cellulosic biofuel on which to base the 

percentage standard for 2011, it is important to consider the ability of the biofuel to 
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generate cellulosic RINs under the RFS2 program. 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 crop residue, 

slash, pre-commercial 

thinnings and tree 

residue, annual 

covercrops, 

switchgrass, and 

miscanthus; cellulosic 

components of 

separated yard waste; 

cellulosic components 

of separated food 

waste; and cellulosic 

components of 

separated MSW 

Any 3 

(cellulosic 

biofuel) 
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Cellulosic 

Diesel, Jet Fuel 

and Heating Oil 

Cellulosic Biomass 

from crop residue, 

slash, pre-commercial 

thinnings and tree 

residue, annual 

covercrops, 

switchgrass, and 

miscanthus; cellulosic 

components of 

separated yard waste; 

cellulosic components 

of separated food 

waste; and cellulosic 

components of 

separated MSW 

Any 7 

(cellulosic 

diesel) 

Cellulosic 

Naphtha 

Cellulosic Biomass 

from crop residue, 

slash, pre-commercial 

thinnings and tree 

residue, annual 

covercrops, 

switchgrass, and 

Fischer-Tropsch 

process 

3 

(cellulosic 

biofuel) 
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miscanthus; cellulosic 

components of 

separated yard waste; 

cellulosic components 

of separated food 

waste; and cellulosic 

components of 

separated MSW 

Of the five facilities that we currently believe could contribute to the volume of 

commercially available cellulosic biofuel in 2011, four would produce alcohols from 

cellulosic biomass and one would produce diesel from cellulosic biomass. None of the 

facilities we have evaluated would produce cellulosic naphtha through a Fischer-Tropsch 

process. In 2011 the primary biofuel Range fuels has indicated will be produced from 

their facility is methanol. While there is currently no pathway for cellulosic methanol to 

generate RINs, Range has engaged EPA in discussion regarding the addition of a 

pathway for cellulosic methanol. 

 Two of the facilities shown in Table II.A.4-1, KL Energy and Range Fuels, 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 
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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, it will be added to Table 1 to §80.1426 and producers can then 

make use of it to generate cellulosic RINs. 

 As described in Section II.A, Range Fuels will begin making predominantly 

methanol, and no approved pathway currently exists under the RFS program to generate 

RINs for methanol. However, Range has been in discussions with EPA concerning a 

petition under §80.1416 for the generation of RINs for methanol made from woody 

biomass as well as the generation of cellulosic RINs for the portion of biodiesel made 

from cellulosic methanol. These pathways are similar to pathways we have modeled in 

the past. For the purposes of projecting cellulosic volumes for 2011, we believe that the 

methanol from Range Fuels has the potential for being approved for generation of 

cellulosic RINs and is therefore appropriate for being included in the volumes that we 

believe are potentially attainable in 2011. 

B. Cellulosic Feedstocks 

Cellulosic biofuel technologies are different from other biofuel technologies 

because they convert the cellulose and other very difficult to convert compounds into 
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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. The remainder of cellulosic feedstocks consists primarily 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 cellulosic feedstocks 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 

evaluation 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 fuels produced, and a list of many of the companies which we 

 

18 DOE. “Biomass Program: ABC’s of Biofuels”. Accessed at: 

http://www1.eere.energy.gov/biomass/abcs_biofuels.html#content 
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learned are pursuing the technology (or something very similar to the technology listed in 

the category). EPA is currently tracking the progress of more than 100 cellulosic biofuel 

projects, many of which are not listed in the following table. The inclusion of a specific 

company in the table or technical discussion that follows should not be interpreted as an 

endorsement of the listed company. The cellulosic biofuel industry continues to progress 

at a rapid pace and many companies not listed in this assessment may still produce 

significant volumes of cellulosic fuel in future years. 
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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, 
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TRI, Nature’s Fuel 

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, 

Lanzatech 

Acid Hydrolysis of cellulose to 

intermediate; hydrogenation 

using Thermochemical syngas 

from non-cellulose fraction 

Ethanol, 

Other 

alcohols 

Zeachem 

Depolymerization Catalytic Depolymerization of 

Cellulose 

Diesel, Jet 

Fuel or 

Naphtha 

Cello Energy, Covanta, Green 

Power 

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 
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 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 a comprehensive list of all new biofuel 

technologies, but rather a description of some of the more prominent of the new biofuel 

technologies that serve to provide a sense of the technology categories listed above. The 

process technology summaries are based on information provided by the respective 

companies. EPA has not been able to confirm all of the information, statements, process 

conditions, and the process flow steps necessary for any of these processes and 

companies. 

 1. Biochemical

 Biochemical conversion refers to a broad grouping of processes that use 

biological organisms to convert cellulosic feedstocks into biofuels. While no two 

processes are identical, many of these processes follow a similar basic pathway to convert 

cellulosic materials to biofuel. The general process of most biochemical cellulosic 

biofuel processes consists of five main steps: feedstock handling, pretreatment, 

hydrolysis, fermentation/fuel conversion, and distillation/separation. The feedstock 

handling step reduces the particle size of the incoming feedstock and removes any 

contaminants that may negatively impact the rest of the process. In the pretreatment step 
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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. 
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Figure IV.C.1-119

19 Image From: http://www.afdc.energy.gov/afdc/ethanol/production_cellulosic.html 
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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, some of 

the variations to this general process, and some of the advantages and disadvantages of 

the biochemical process of producing biofuel from cellulosic materials as compared to 

other fuel production processes. 

 Three of the five companies that EPA believes may produce cellulosic biofuel in 

2011 plan to use a biochemical process to produce biofuels. All three of these 

companies, Dupont Danisco Cellulosic Ethanol, Fiberight, and KL energy, all plan to use 

an enzymatic hydrolysis. One of the biggest appeals of the biochemical pathway is the 

relatively low capital costs of these projects compared to other cellulosic biofuel 

facilities. Biochemical projects are also less dependent on economies of scale for 

profitability, making smaller and less capital intensive commercial facilities more 

feasible. 

 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 
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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. While this may provide financial benefits 

for the cellulosic biofuel producer, it will not impact the lifecycle green house gas 

emissions of the process. 

 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 nonbiogenic 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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 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 docket20. 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 

 

20 Wyborny, Lester. “In-Depth Assessment of Advanced Biofuels Technologies.” Memo to the docket, 

November 17, 2010. 
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 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 six-carbon sugars that are then fed to 
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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. 

 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 
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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 will be 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 
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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. 

 d. Fuel Production 

 After the cellulosic biomass has been hydrolyzed to simple sugars, this sugar 

solution is converted to fuel by biological organisms. In some biochemical fuel 

production processes the sugars produced from the fermentation of the hemicellulose, 

which are mainly five-carbon sugars, are converted to fuel in a separate reactor and with 

a different set of organisms than the sugars produced from the cellulose hydrolysis, which 

are mainly six-carbon sugars. Others processes, however, produce fuel from the five and 

six-carbon sugars in the same reaction vessel. 

 A wide range of biological organisms can be used to convert the simple sugars 

into fuel. These include yeasts, bacteria, and other microbes, some of which are naturally 

occurring and others that have been genetically modified. The ideal biological organism 

converts both five and six-carbon sugars to fuel with a high efficiency, is able to tolerate 

a range of conditions, and is adaptable to process sugar streams of varying compositions 

that may result from variations in feedstock. Many cellulosic biofuel producers have 

their own proprietary organism or organisms optimized to produce the desired fuel from 

their unique combination of feedstock, pretreatment and hydrolysis processes, and fuel 
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conversion conditions. Other cellulosic fuel producers license these organisms from 

biotechnology companies who specialize in their discovery and production. 

 The different biological organisms being considered for cellulosic biofuel 

production are capable of producing many different types of fuels. Most cellulosic 

biofuel producers are working with organisms that produce ethanol. In many ways this is 

the simplest 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 has the potential to be blended 

into gasoline in greater concentrations than ethanol and therefore has a potentially greater 

market as well as value due to its higher energy content. Yields for butanol, however, are 

currently lower per ton of feedstock than ethanol. 

 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 can potentially be blended into conventional 

gasoline and diesel for use 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 result 

in a single compound, such as iso-octane, that would need to be blended into petroleum 

gasoline in order to be used as transportation fuel, 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. The 
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yields of fuel produced by these organisms through biochemical processes are currently 

significantly lower than those processes that produce ethanol and other alcohols. 

 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 are 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 content 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, natural gasoline, or some other approved denaturant is then added to 

the ethanol before the fuel is stored. 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. 
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 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. 

 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. 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 

the aforementioned technical memo to the docket. 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 
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to one capable of producing fuel at a commercial scale. Companies such as Iogen, 

DuPont Danisco Cellulosic Ethanol, Fiberight and KL Energy are just beginning to 

market the fuel they are producing at their first small scale commercial fuel production 

facilities. 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 mandates put into place by the RFS2 program have 

created a demand for cellulosic biofuels, and higher crude oil prices can also make 

cellulosic biofuels more economically attractive. The biochemical production process 

also has several important benefits including relatively low capital costs, highly selective 

fuel production, and flexibility in the type of fuel produced. 

 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. Another advantage that biochemical processes have over 

other cellulosic fuel production processes is their high selectivity in the fuels they 
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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 of sugar. Finally, there is a potential to further 

decrease the production costs of cellulosic biofuels using biochemical processes. Unlike 

other production methods such as gasification which are relatively mature technologies, 

biochemical production of fuels from cellulosic feedstock 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. Path to Commercialization 

 While there are many promising qualities of the biochemical fuel production 

process, we have identified several different aspects of the process which can be further 

improved. The pretreatment process can be improved to speed 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 can also be improved. Both these improvements will increase the 

fuel yield per ton of cellulosic feedstock, reducing the operating costs of the process. 

Finally, the enzyme production process can be further optimized, which would lower the 

price for enzymes and improve the economics of hydrolyzing cellulose to sugars. 
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 Another opportunity for improvement would be 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 component 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 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. 

 These various improvements to cellulosic biofuel plants would make biochemical 

processes more cost-competitive with petroleum and other cellulosic biofuels. For more 

details on the potential cost impacts of these improvements, see the aforementioned 

technical memo which has been added to the docket of this rule. 

 2. Thermochemical 

 Thermochemical conversion involves biomass being broken down into syngas 

(primarily CO and H2) using heat and upgraded to fuels using a combination of heat and 
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pressure in the presence of catalysts.21 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, an optimized process to produce only one 

alcohol such as ethanol, or it can 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.22 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 also 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 mixedalcohols route refer to NREL technical documentation.23 

 

21 US. DOE. Technologies: Processing and Conversion. Accessed at: 

http://www1.eere.energy.gov/biomass/processing_conversion.html on October 28, 2008 22 EERE, DOE, Thermochemical Conversion, & Biochemical Conversion, Biomass Program 

Thermochemical R&D . http://www1.eere.energy.gov/biomass/thermochemical_conversion.html 

http://www1.eere.energy.gov/biomass/biochemical_conversion.html 

23 Aden, Andy, Mixed Alcohols from Woody Biomass – 2010, 2015, 2022, National Renewable Energy 

Laboratory (NREL), September, 23 2009. 
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Figure IV.C.2-1 

Cellulosic Ethanol Thermochemical Gasification Process 
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Figure IV.C.2-2 is a block diagram of a 

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biomass to liquids (BTL) process which produces diesel fuel and naphtha through a 

thermochemical process. 
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Figure IV.C.2-2 

Biomass to Liquids (BTL) Thermochemical Gasification Process 
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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.24 

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. 

 

24 Lin Wei, Graduate Research Assistant, Lester O. Pordesimo, Assistant Professor 

Willam D. Batchelor, Professor, Department of Agricultural and Biological Engineering, 

Mississippi State University, MS 39762, USA, Ethanol Production from Wood: Comparison of Hydrolysis 

Fermentation and Gasification Biosynthesis, Paper Number: 076036, Written for presentation at the 2007 

ASABE Annual International Meeting. Minneapolis Convention Center, Minneapolis, MN, 17 - 20 June 

2007 
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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 a water-gas shift reaction 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. 

 A carefully integrated conventional steam cycle produces process heat and 

electricity (excess electricity is exported). Pre-heaters, steam generators, and superheaters generate steam that drives turbines on compressors and electrical generators. The 

heat balance around a thermochemical unit or thermochemical combined unit must be 

carefully designed and tuned in order to avoid unnecessary heat losses.25 These facilities 

 

25 S. Phillips, A. Aden, J. Jechura, and D. Dayton, National Renewable Energy Laboratory, Golden, 

Colorado 80401-3393, T. Eggeman, Neoterics International, Inc., Thermochemical Ethanol via Indirect 

Gasification and Mixed Alcohol Synthesis of Lignocellulosic Biomass, Technical Report, NREL/TP-510-

41168, April 2007 
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greatly increase the thermal efficiency of these plants, but they add to the very high 

capital costs of these technologies. 

a. Ethanol based on a Thermochemical Platform 

 Conceptual designs and techno-economic models have been developed for 

ethanol production via mixed alcohol synthesis using catalytic processes. The proposed 

mixed alcohol process produces a mixture of ethanol along with higher normal alcohols 

(e.g., n-propanol, n-butanol, and n-pentanol). The by-product higher normal alcohols 

have value as commodity chemicals and fuel additives. 

 The liquid from the low-pressure separator is dehydrated in vapor-phase 

molecular sieves, producing the dehydrated mixed alcohol feed into a methanol/ethanol 

overhead stream and a mixed, higher molecular weight alcohol bottom stream. The 

overhead stream is further separated into a methanol stream and an ethanol stream. 

 

 Two companies which are pursuing ethanol based on a thermochemical route are 

Range Fuels and Enerkem. Range Fuels completed construction of their first commercial 

facility in Soperton, Georgia in the first quarter of 2010 and began the production of 

cellulosic biofuel in the third quarter of 2010. In the first phase of operation Range will 

use wood chips as a feedstock but they also plan to investigate the possibility of using 

other non-food biomass. In its initial phase, the Range plant is expected to produce up to 

4 million gallons per year of primarily methanol as well as a small quantity of ethanol 
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which they intend to sell into the transportation fuel market. After the company is 

confident in its operations, Range will begin efforts to expand the plant and add 

additional reaction capacity to increase production of ethanol and other alcohols. 

Enerkem is pursuing cellulosic ethanol production via the thermochemical route. 

The Canadian-based company was recently announced as a recipient of a $50 million 

grant from DOE to build a woody biomass-to-ethanol plant in Pontotoc, MS. The U.S. 

plant is not scheduled to come online until 2012, but Enerkem’s 1.3 MGY demonstration 

plant in Westbury, Quebec is currently operational. According to the company, plant 

construction in Westbury started in October 2007 and it began producing syngas in late 

2009. After the successful testing of the syngas unit Enerkem added methanol production 

capabilities and began producing methanol in 2010. The last step for the Westbury plant 

will be for Enerkem to add a reactor to convert the methanol to ethanol and other higher 

order alcohols. While it is unclear at this time whether any cellulosic ethanol will be 

produced in 2011 Enerkem has informed EPA that they do not intend to export any 

cellulosic fuel to the United States. If Enerkem does export some of its cellulosic biofuel 

to the U.S. however, it could be used to 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 catalyst. Current FT 
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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. The primary products resulting from this separation are 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, blended down 

with high octane blendstocks (i.e., ethanol), or upgraded to a higher octane blendstock to 

have much value for use in gasoline. 

 Choren is a 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 which includes low temperature gasification, 

high temperature gasification, and endothermic entrained bed gasification. Choren 

designed its gasification reactor with three stages to more fully convert the feedstock to 

syngas. Choren will be building a commercial Plant in Freiberg/Saxony, Germany that is 

expected to be operational in 2011 or 2012. Initially, the plant will use biomass from 

nearby forests, the wood-processing industry, and straw from farmland. Although any 

fuel produced in 2011 by its Freiberg/Saxony plant and marketed commercially would 

most likely be used in Europe, it is possible that some of that fuel could be exported to 

the US. Choren is also planning to build a commercial thermochemical/biomass-toliquids (BTL) plant in the U.S. after their Freiberg/Saxony plant is operational in 

Germany. 
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Baard Energy is a U.S. company which plans on utilizing a thermochemical 

technology for producing diesel fuel and naphtha. Baard, however, plans on primarily 

combusting coal and cofiring biomass with the coal. Cofiring the biomass with the coal 

will make their first plant more like the coal-to-liquids plants which are operating today, 

which may help to convince investors that this technology is already tested. Baard’s coal 

and biomass-to-liquids plant is not expected to be operational until at least 2012. 

One challenge for the companies pursing the thermochemical route is the 

significant capital costs associated with these technologies. 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. However, because of this cleaning step, 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 
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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 Section IV.C.3.a below, include both INEOS Bio 

and Coskata. As of December 4, 2009 INEOS Bio (along with partner New Planet 

Energy) has been selected for a $50MM DOE grant for the construction of an 8 MGPY 

plant in River County, Florida. This plant is projected 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 

pursuing the second process strategy, described in Section IV.C.3.b below, 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. 

 a. Biochemical Step Following Thermochemical Step 
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 One hybrid strategy involves the gasification of all feedstock material to syngas 

before being processed into ethanol using a biochemical fermenter. 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. 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 to be 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. 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 
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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 selfsustaining and do not require periodic replacement. They are; however, susceptible to 

bacterial and viral infections which requires periodic cleaning of the fermentation 

reactors. 

 b. Concurrent Biochemical and Thermochemical Steps 

 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 lignin-based syngas with the product of the fermented 

stream. The feedstock first undergoes acid hydrolysis to break down the cellulose and 

hemicellulose. Before fermentation, the unfermentable portion of feedstock (lignin, ash 

and other residue) is fractioned and sent to a gasifier. Concurrently, the hydrolyzed 

cellulose and hemicellulose is fermented using an acetogen microorganism. These 

acetogens occur naturally, and therefore do not have to be modified for this process. 

These acetogens convert both five-carbon and six-carbon sugars from the hydrolized 

feedstock to acetic acid. This reaction creates no carbon dioxide, unlike traditional 
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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 be sold in addition to ethanol or further converted to other compounds for 

sale in the chemicals market. Typical yields for this technology are predicted in the 130 

– 150 gallon per ton range. 

 4. Pyrolysis and Depolymerization 

 Pyrolysis and depolymerization are 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 as being primarily a thermal technology, however, 

newer pyrolysis technologies are being developed which are attempting to integrate the 

use of some catalysts. These are all unique processes, typically with single companies 

developing the technologies, so they are discussed separately below. 

a. Pyrolysis Diesel Fuel and Gasoline 
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Pyrolysis oils, or bio-oils, are produced by thermally cracking cellulosic biomass 

at lower temperatures than the gasification process, thus producing a liquid instead of a 

synthesis gas.26 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. While one of the finished fuels 

produced by the pyrolysis process is diesel fuel, a significant amount of gasoline would 

likely be produced as well. There are two main reaction pathways currently being 

explored: a two step pyrolysis pathway, and a one step pyrolysis pathway. 

The simplest technology used for the two-step pyrolysis approach is called fast 

pyrolysis. The fast pyrolysis technology uses sand in a fluidized bed to transform biofuels into bio-oil. This is purely a thermal process, where the sand’s (or other solid's) 

role is to transfer heat to the biomass. For two reasons, the bio-oils from fast pyrolysis 

technologies must be upgraded. 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 or 

it won’t meet transportation fuel specifications. 

 

26 DOE EERE Biomass Program. “Thermochemical Conversion Processes: Pyrolysis” 

http://www1.eere.energy.gov/biomass/thermochemical_processes.html, November 6, 2008. 
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Another approach to fast pyrolysis being pursued by several companies would be 

to substitute a catalyst in place of sand and the catalyst would be able to stabilize the 

resulting bio-oil in addition to helping depolymerize the biomass to liquids. Although the 

resulting bio-oil is stable, it still has to be upgraded into a transportation fuel, since it 

would still have a high level of oxygenated compounds. 

The National Renewable Energy Laboratory (NREL) is working on a “hot 

filtration” technology that is intended 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 may be 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 uses fast 

pyrolysis to convert dry waste biomass and energy crops into different products including 

bio-oil. The bio-oil produced is polar due to its high oxygen content and it contains up to 
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25% water which is intimately mixed and does not easily separate into another phase with 

time. Since the bio-oil contains significant amounts of both oxygen and 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 bio-oil 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. 

 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 demonstration plant 

is located in West Lorne Ontario, Canada. Dynamotive continues to work on a 

technology for converting its bio-oil 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 would be possible for 

Dynamotive to set up an agreement with a refining company which could upgrade its biooil to a #2 fuel oil or diesel fuel using existing refinery hardware so that the fuel would 

qualify under the RFS2 program and contribute to meeting 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 
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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 U.S. National 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, their technology would be competitive with #2 fuel oil produced from crude oil 

priced at about $40 per barrel. Envergent is licensing this technology as well as working 

with a U.S. oil company to test out this technology in a commercial setting 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 in September 2008 aimed at collaborating to maximize the benefit of their 

respective institutional interests in second generation biofuels. Petrobras is also 

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 also hopeful that a one-step 
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pyrolysis technology can be developed to convert biomass directly to transportation fuels, 

but believes that the two step process may be more economically attractive. 

b. Catalytic Depolymerization 

 There are several companies pursuing catalytic depolymerization including 

Covanta, Cello Energy and Green Power. 

 Covanta is currently operating 45 energy-from-waste facilities which annually 

convert 20 million tons of municipal solid waste materials into 9 million megawatt hours 

of electricity and 10 billion pounds of steam, which is sold to a variety of industries. 

Covanta has secured license rights to a catalytic depolymerization technology developed 

by AlphaKat GmbH. Covanta constructed an AlphaKat demonstration plant in West 

Wareham, Massachusetts designed to process 45 tons of waste per day into renewable 

diesel fuel. If successful, the total liquid fuel production capacity of this demonstration 

plant will be 1 million gallons per year. This plant started up in mid-2010 and after 

experimenting with the technology to further understand its capabilities, Covanta expects 

to use the liquid distillate fuel produced from this demonstration plant within its own 

plant as heating oil and nonroad diesel fuel. 

 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 
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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 to 55 

cetane and typically contains a very low concentration 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 also estimated to be very low. 

 In December 2008, Cello completed construction of a 20 million gallon per year 

commercial demonstration plant. However, they are still working to resolve process 

issues that have arisen upon scaleup from their pilot plant. However, we are doubtful that 

Cello will be able to produce any volume of cellulosic biofuel in 2011 as described more 

fully in Section II. 

 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, 
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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 by the company, this 

technology may fit the description for catalyzed pyrolysis reactions described above, but 

we have categorized this as a separate catalytic depolymerization technology due to its 

unique features. 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 any solids which 

are present and are distilled into typical fuel streams including naphtha, diesel fuel, 

kerosene, and fuel oil. According to publically available information about this 

technology, the process reportedly produces 120 gallons per ton of feedstock introduced 

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 

would be used for heating the process. Some carbon dioxide may also be formed and 

released from the process. 

 Greenpower completed construction of a demonstration plant located in Fife, 

Washington in March of 2008. Greenpower is working on obtaining additional funding 

and an air permit through the State of Washington Environmental Office. While we do 

not expect that Greenpower will have its plant operational in 2011, it is possible that 

outstanding issues could be resolved to allow this company to produce renewable fuel 

that could help refiners comply with the cellulosic biofuel volume standard for 2011. 
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5. Catalytic Reforming of Sugars to Gasoline

 Virent Biorefining is pursuing a process called “Bioforming” which functions 

similar to the gasoline reforming process used in the refining industry. Hence, this is a 

significantly different technology than the 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 producing about 30 gallons per day of 

high octane naphtha. Commercialization of the Virent process is expected to occur 

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 Bioforming work, Virent is working on a technology 

to break down cellulose into sugars upstream of its technology which reforms sugars to 

gasoline. 
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V. Changes to RFS Regulations 

 EPA proposed two revisions to the general RFS program regulations. First, we 

proposed to allow the generation of "delayed RINs" for fuel produced between July 1, 

2010 and December 31, 2010 using certain fuel pathways that were not in Table 1 to 

§80.1426 on July 1, 2010, but which could possibly be added after July 1 if they are 

determined to meet the applicable GHG reduction thresholds. Under the proposal, 

delayed RINs could be generated only if the pathways were indeed approved, and only 

for quantities reflecting fuel produced between July 1, 2010 and the effective date of a 

new RIN-generating pathway. In a previous action, we finalized the provision for 

delayed RINs for application only to biodiesel produced from canola oil through 

transesterification using natural gas or biomass for process energy.27 In today's action we 

are modifying the delayed RINs provision to make it more broadly applicable to other 

renewable fuel production pathways. 

 The second program modification that we proposed would establish procedures 

and evaluation criteria for petitions requesting EPA authorization of an aggregate 

compliance approach to renewable biomass verification for feedstocks grown in foreign 

countries, akin to that applicable to crops and crop residue grown within the U.S. In 

today's rule we are finalizing amendments to the RFS regulations to implement this 

provision. 

 

27 75 FR 59622, September 28, 2010 
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 A. Delayed RIN Generation for New Pathways 

 For the March 26, 2010 RFS2 final rule (75 FR 14670), we attempted to evaluate 

and model the lifecycle GHG emissions associated with as many renewable fuel 

production pathways as possible so that producers and importers of qualifying renewable 

fuels could generate RFS2 RINs beginning on July 1, 2010. However, we were not able 

to complete the evaluation of all pathways that we had planned. In the preamble to the 

final RFS2 rule we announced our intention to complete the evaluation of three specific 

pathways after release of the RFS2 final rule: grain sorghum ethanol, pulpwood biofuel, 

and palm oil biodiesel (see Section V.C of the RFS2 final rule, 75 FR 14796). To this list 

we later added biodiesel produced from canola oil as this biofuel was produced under 

RFS1 and was also expected to participate in the RFS2 program at the program’s 

inception. 

 In the NPRM associated with today’s final action, we proposed a new regulatory 

provision that could potentially allow RINs to be generated for fuel produced on or after 

July 1, 2010 representing these four fuel pathways even though they were not in Table 1 

to §80.1426 as of July 1, 2010. Under this proposed provision, RINs could be generated 

only if the pathways were indeed approved as valid RIN-generating pathways, and only 

for volumes of fuel produced between July 1, 2010 and the effective date of a new RINgenerating pathway added to Table 1 to §80.1426. Somewhat different procedures were 

proposed for the generation of delayed RINs for volumes for which RINs had never been 

generated, and those for which RINs with a D code of 6 had been generated pursuant to 
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§80.1426(f)(6) by a grandfathered facility. In a final rule published on September 28, 

2010, we finalized regulatory provisions for these "delayed RINs” only for application to 

biodiesel produced from canola oil through transesterification using natural gas or 

biomass for process energy, since that action added only this one new pathway to Table 1 

to §80.1426. In that final action we also discussed many of the comments received in 

response to the proposed provision for delayed RINs, our response to relevant comments, 

and the resulting modifications we made to the regulatory provisions. 

 However, we deferred for future consideration one set of comments related to 

delayed RINs in the September 28, 2010 final rule which established a new RINgenerating pathway for biodiesel produced from canola oil. In response to the NPRM, 

two commenters requested that the provision for delayed RINs be made applicable to 

pathways other than the four we proposed, such as pathways utilizing camelina and 

winter barley. We agree with these commenters that the delayed RINs provision should 

not necessarily be limited to fuel produced by grain sorghum ethanol, pulpwood biofuel, 

palm oil biodiesel, or canola oil biodiesel (assuming they are ultimately approved for RIN 

generation). As the commenters suggested the same rationale that justifies authorization 

of delayed RINs for these pathways could also justify the authorization of delayed RINs 

for other pathways that were commercially viable at the start of the RFS2 program, but 

which EPA was unable to address in time for RINs to be generated at the start of the 

program. Therefore, today’s final rule does not limit the applicability of the delayed 

RINs provision to any particular pathways, but does include general limitations that will 

ensure that the provision is limited in scope to address difficulties related to RFS2 
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program startup. Among other provisions, in today’s rule we are specifying that the 

delayed RINs provision is limited to biofuel pathways in use as of July 1, 2010 for the 

primary purpose of producing transportation fuel, heating oil, or jet fuel for commercial 

sale. We believe that this criterion, among others discussed below, will properly define 

those pathways for which fuel producers should be accorded flexibility in light of EPA’s 

inability to finalize its assessments in time for RFS2 start-up, and for which sufficient 

information likely existed as of July 1, 2010, for EPA to make lifecycle GHG emissions 

determinations. 

 The modified provisions will apply equally to EPA approvals of new pathways 

directly in response to petitions submitted pursuant to §80.1416, and to those pathways 

that EPA approves through rulemaking. This could include the three pathways that were 

identified in the RFS2 final rule (grain sorghum ethanol, pulpwood biofuel, palm oil 

biodiesel) if they are determined to meet the GHG thresholds, or any other biofuel 

produced from a pathway that was in use as of July 1, 2010 for the primary purpose of 

producing transportation fuel, heating oil, or jet fuel for commercial sale. However, since 

the delayed RINs provision is intended to address program startup issues, we have 

included provisions in this final rule to ensure that the availability of the provision will be 

of limited duration and applicability as described below. 

 We proposed that delayed RINs would be limited to pathways that are approved 

by December 31, 2010. Under the proposal, delayed RINs would have only been 

available for volume produced or imported in 2010. Since we are modifying the 
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delayed RINs provision to make it applicable to other biofuel pathways in addition to the 

four we proposed, we believe it would be appropriate to allow additional time for 

producers and importers of biofuels produced as of July 1, 2010 through pathways not 

included in Table 1 to §80.1426 to both satisfy the eligibility requirements of the delayed 

RINs provision, and to utilize it. Accordingly, today’s rule makes delayed RINs 

available for volumes produced or imported by eligible parties in either 2010 or 2011. If 

we approve pathways for sorghum ethanol, pulpwood biofuel, or palm oil biodiesel in 

time for delayed 2010 and/or 2011 RINs to be used for RFS2 compliance, we will 

specifically add those pathways to the delayed RINs provisions at §80.1426(g) in our 

final actions adding those fuel pathways to Table 1 to §80.1426. Fuels produced in 2010 

or 2010 through other pathways that EPA adds to Table 1 to §80.1426 or approves 

pursuant to §80.1416 will be eligible for delayed RINs if: 

(1) EPA finds that the pathway was in use as of July 1, 2010 for the primary 

purpose of producing transportation fuel, heating oil, or jet fuel for 

commercial sale, and 

(2) A complete petition seeking approval of the pathway is submitted to EPA 

pursuant to §80.1416 by January 31, 2011. 

These requirements are intended to limit the availability of delayed RINs to RINgenerating pathways that could have participated in the RFS2 program at its inception, 

and for which producers and importers have taken reasonable and timely measures to 
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seek EPA approval action. We believe, for example, that parties should not be accorded 

the flexibility to issue delayed RINs if they have not actively pursued EPA approval of 

their pathways in timely manner pursuant to the petition process in §80.1416, and has 

therefore limited the delayed RINs provision to those pathways for which complete 

petitions are submitted to EPA by January 31, 2011. 

 The NPRM approach envisioned that all RINs with a D code of 6 that are retired, 

and all delayed RINs that are generated, must be designated as 2010 RINs. However, 

since we are allowing delayed RINs to be generated for volumes produced in both 2010 

and 2011, we believe that this requirement would no longer be appropriate. Therefore, 

we have modified the delayed RINs provision so that the generation year associated with 

delayed RINs must correspond to the year in which the corresponding volume was 

produced. Delayed RINs generated to represent volume produced in 2010 must be 

designated as 2010 RINs and delayed RINs generated to represent volume produced in 

2011 must be designated as 2011 RINs. Delayed RINs that are generated as 2010 RINs 

will be valid for use in complying with the standards for calendar years 2010 or 2011, 

according to §80.1427(a)(6) and under the rollover restrictions provided at 

§80.1427(a)(5). Likewise, delayed RINs that are generated as 2011 RINs will be valid 

for use in complying with the standards for calendar years 2011 or 2012. Since delayed 

RINs can only be generated for volumes produced or imported in 2010 or 2011, and a 

RIN is only valid for compliance for two compliance years, all delayed RINs will be 

invalid for compliance with the requirements of calendar year 2013 and later. 
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 EPA recognizes that the delayed RINs provision may not provide all biofuel 

producers the opportunity to generate RINs for all of their biofuel produced on and after 

July 1, 2010 if, for instance, a new RIN-generating pathway is not approved until after 

December 31, 2011. EPA has structured the delayed RINs provision in an attempt to 

reduce the impact of EPA’s delay on such parties, while maintaining as closely as 

possible the relationship of RINs to actual fuel production. Limiting the delayed RINs 

provision to qualifying fuel produced in 2010 and 2011 appropriately ties the provision to 

program start-up, and is consistent with the 2-year valid life of RINs. Nevertheless, EPA 

expects that it will be able to complete its lifecycle assessments of pathways for which 

petitions are submitted by January 31, 2010 in time for producers using such pathways to 

avail themselves of the delayed RINs provision as structured in today’s final rule. 

Today’s delayed RIN provision also provides that all requirements that apply 

under the RFS2 rules with respect to identifying fuels for which RINs may be generated, 

the generation and use of RINs, and recordkeeping and reporting, also apply in the 

context of delayed RINs unless specifically provided otherwise in §80.1426(g). For 

example, the existing recordkeeping provisions will require parties to maintain 

documents related to the production and transfer of the volumes of renewable fuel for 

which they are generating delayed RINs. The required records are necessary to document 

that the volumes of fuel for which delayed RINs are generated qualify as renewable fuel 

under the RFS2 program, e.g., that the fuel was produced using feedstocks that meet the 

definition of renewable biomass, and using feedstocks, process energy, and processes that 

conform to the applicable pathway in Table 1 to §80.1426 or approved pursuant to 
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§80.1416. Furthermore, the requirements concerning the transfer of renewable fuel for 

which parties are generating delayed RINs is necessary to ensure that the fuel was, in 

fact, transferred by the delayed RIN-generating party. 

B. Aggregate Compliance Approach for Renewable Biomass from 

Foreign Countries 

 As part of the NPRM, we proposed new regulatory provisions to establish 

procedures for submitting petitions to request EPA authorization of an aggregate 

compliance approach to renewable biomass verification for feedstocks grown in foreign 

countries,28 akin to that applicable to planted crops and crop residue from existing 

agricultural land within the U.S. In the NPRM, we referenced the preamble discussion in 

the final RFS2 regulations in which we indicated that, while we did not have sufficient 

data at the time to make a finding that the aggregate compliance approach adopted for 

domestically-grown crops and crop residues would be appropriate for foreign-grown 

feedstocks, we would consider applying the aggregate compliance approach for 

renewable biomass on a country by country basis if adequate land use data becomes 

available. 

In the NPRM, EPA proposed a process by which entities might petition EPA for 

approval of the aggregate compliance approach for renewable fuel feedstocks either in a 

foreign country as a whole or in a specified geographical area within a country. The 

 

28 75 FR 42238, 42262, July 20, 2010 
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proposed regulations would have allowed petitioners to request authorization of the 

aggregate compliance approach for specific feedstocks or for all planted crops and crop 

residue, and EPA sought comment on these options. The proposed regulations also 

included a general criterion and a number of considerations that EPA would use in 

evaluating petitions, and specified a list of elements that would be required in a petition. 

The preamble to the proposed rule included a description of the process by which EPA 

proposed to make decisions concerning any petitions received. 

EPA received a number of comments on the proposal and is finalizing an 

approach similar to that which was proposed, with some significant modifications, as 

described below. 

1. Criteria and Considerations

In developing the 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. EPA is finalizing an approach similar 

to that which was proposed and that which was applied to planted crops and crop residue 

from U.S. agricultural land. Petition approval for application of the aggregate 

compliance approach will be based on a finding by EPA that such an approach can 

provide reasonable assurance that planted crops and crop residue from a given foreign 

country meet the definition of renewable biomass and will continue to meet the definition 

of renewable biomass, as demonstrated through the submission of credible, reliable and 
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verifiable data. Based on our experience in making a comparable finding for U.S.-grown 

crops and crop residues, we are finalizing a number of more specific factors that EPA 

will consider when determining whether this finding should be made, as described below. 

• Whether there has been a reasonable identification of the “2007 baseline 

area of land,” defined as the total amount of cropland, pastureland, and 

land that is equivalent to U.S. Conservation Reserve Program land in the 

country in question that was actively managed or fallow and nonforested 

on December 19, 2007, taking into account the definitions of terms such as 

“cropland,” “pastureland,” “planted crop,” and “crop residue” included in 

the final RFS2 regulations. 

• Whether information on the total amount of cropland, pastureland, and 

land that is equivalent to U.S. Conservation Reserve Program land in the 

country in question for years preceding and following calendar year 2007 

shows that 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 planted crops and crop residue will continue to use 

agricultural land within the 2007 baseline area of land identified into the 

future, as opposed to clearing and cultivating land not included in the 2007 

baseline area of land. 
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• Whether there is a reliable method to evaluate on an annual basis whether 

the 2007 baseline area of land is being or has been exceeded. 

• Whether a credible and reliable entity has been identified to conduct data 

gathering and analysis, including annual identification of the aggregate 

amount of cropland, pastureland, and land that is equivalent to U.S. 

Conservation Reserve Program land, that is needed for an annual EPA 

evaluation of the aggregate compliance approach, and whether the data, 

analyses, and methodologies are publicly available.. 

• Whether the ministry (or ministries) or department(s) of the national 

government with primary expertise in agricultural land use patterns, 

practices, data, and statistics of the country in question supports the 

petition and have verified in writing the accuracy and veracity of the 

information submitted in the petition and agreed to review and verify the 

data submitted on an annual basis to facilitate EPA’s annual assessment of 

the 2007 baseline area of land. 

EPA requested comments on the proposed general criteria and specific 

considerations for approving the aggregate compliance approach for non-domestically 

grown feedstocks. EPA received a number of comments in support of the proposed 

general criteria, stating that EPA has outlined a straightforward, science-based approach 

that is necessary to avoid unfairly disadvantaging foreign renewable fuel producers and to 

ensure availability of adequate supplies of renewable fuel. Commenters noted that the 

establishment of a petition process for applying the aggregate compliance approach to 
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foreign grown feedstocks levels the playing field for foreign renewable fuel producers 

and ensures that the U.S. government is not posing a barrier to trade contrary to its WTO 

obligations. EPA also received comments in opposition of the proposed petition process 

that stated that the U.S. aggregate compliance approach is not sound, and that the data 

that would be relied on to establish the aggregate compliance approach for foreign 

feedstocks would be even less reliable than that used by EPA to support its finding for the 

domestic aggregate compliance approach. EPA also received comments arguing that the 

use of foreign feedstocks and importation of foreign renewable fuels should be 

disallowed under the RFS2 program. 

EPA believes that the aggregate compliance approach for renewable biomass is an 

appropriate tool that, in the right circumstances, can fully ensure that the EISA renewable 

biomass requirements are satisfied while easing the burden on renewable fuel producers 

and their feedstock suppliers. The logic for the approach is described in the preamble to 

the RFS2 rule. EPA believes that in applying the criteria adopted today for assessing 

petitions for application of the aggregate approach to foreign countries, and considering 

the factors specified in the rule, that EPA will be able to properly identify situations 

where the aggregate compliance approach can be appropriately applied in foreign 

countries. The public will have an opportunity to review petitions, and to apprise EPA of 

any concerns regarding the data relied upon, or the logic and rationale for application of 

the aggregate compliance approach to a particular country. 
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EPA also believes that establishing the aggregate compliance approach petition 

process for planted crops and crop residue from foreign countries is appropriate and fair 

since the renewable biomass verification process is currently streamlined for producers 

using U.S. planted crops and crop residue, and EPA believes that it should clarify the 

process and substantive considerations needed to extend this streamlined compliance 

approach to foreign planted crops and crop residue. The aggregate compliance approach 

petition process for planted crops and crop residue from foreign countries is intended to 

provide foreign renewable fuel producers with a similar level of streamlining for 

qualification of renewable biomass as provided to domestic producers. 

EPA disagrees with the commenter that argues that the use of foreign feedstocks 

and importation of foreign fuels should be disallowed, as nothing in the Clean Air Act 

(CAA) prevents foreign products from being used towards meeting the RFS2 

requirements. 

2. Applicability of the Aggregate Approach

The aggregate compliance approach for domestic agricultural feedstocks applies 

to all planted crops and crop residue that could be used in renewable fuel production from 

existing agricultural land in the U.S. EPA solicited comment on whether the rules 

establishing the aggregate compliance approach petition process for foreign feedstocks 

should allow petitions and EPA approval for a single, or limited number, of feedstocks, 
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or for a limited geographic area within a country, or whether we should only allow 

petitions and EPA approval at the national level and for all planted crops and crop 

residue. 

The proposed rule spoke generally of “feedstocks,” and we received one comment 

in support of our proposed approach to allow petitions to be submitted for specific 

feedstocks. In particular, the commenter argued that the reduced regulatory burden on 

U.S.-grown corn should be extended to Brazilian-grown sugarcane. We believe that the 

rationale underlying the comment is not fully accurate, as the aggregate compliance 

approach in the U.S. applies to all planted crops and crop residue, not just corn. Upon 

further consideration, EPA believes that it is highly unlikely that data and analysis could 

support application of the aggregate approach to feedstocks other than crops and crop 

residue. Furthermore, we believe that the same data and analysis would be needed to 

justify application of the aggregate compliance approach to individual crops as would be 

needed to justify its application to all planted crops and crop residue within a given 

geographic area. Thus, it would be most efficient, and most consistent with the current 

approach in the U.S., to authorize the aggregate compliance approach for all planted 

crops and crop residue within a geographic area at one time, rather than on a crop-bycrop basis. This approach will simplify the regulations, as it permits EPA to specify the 

data, analyses and considerations related specifically to supporting the aggregate 

compliance approach for those types of feedstock. We have therefore modified the final 

rule to specify that petitions and EPA approval will apply to all planted crops and crop 

residue from existing agricultural land in a foreign country. 
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Several commenters supported the application of the aggregate compliance 

approach petition process on a national basis, but not for a geographical subset of a 

foreign country. These commenters argued that applying the process on a national basis 

is fair because it is consistent with the U.S. aggregate approach, which was applied on a 

national level. Furthermore, the commenters argue that geographical subsets should not 

be allowed because doing so would promote “cherry picking” of data by private parties to 

show that a certain region is not experiencing conversion of forest and ecologically 

sensitive lands, even when on a national level, those lands are decreasing. Commenters 

also argue that local governments do not have the enforcement capability and land 

management policies that national governments have. 

In contrast, one commenter believed that parties should be able to petition for the 

aggregate compliance approach to apply to specific geographical regions within a foreign 

country, citing data from Brazil implying that almost all sugarcane is harvested from a 

certain region and therefore the aggregate compliance approach could successfully be 

applied to that region only. 

EPA agrees with those commenters that believe that the aggregate compliance 

approach petition process should be allowed only at the national level. Applying the 

petition process on the national level is consistent with the U.S. approach and will 

therefore harmonize application of the approach where it has been approved. Moreover, 

EPA believes that national-scale land use data is typically the most reliable and 
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transparent, and can more easily be confirmed by the national government. Furthermore, 

national level data most accurately reflects the broader effects of renewable fuel 

feedstock production on land use patterns. 

 

 3. 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 to assess the area of land (acreage) available in 2007 in the United States for 

production of crops and crop residues that meet the CAA definition of renewable 

biomass. In the case of a petition to apply the aggregate compliance approach in a 

foreign country, when considering the information and data submitted by the petitioner, 

EPA proposed and is finalizing a requirement that data supporting the petition be 

credible, reliable and verifiable. EPA will evaluate such information on a case-by-case 

basis, but expects that data supporting petitions will be at least as credible, reliable, and 

verifiable as the USDA data used to make the determination for U.S. agricultural land. 
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EPA noted in the preamble to the proposed rule that when evaluating whether the 

data relied on are credible, reliable, and verifiable, EPA would 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. In the proposal, EPA noted that it is important for the national government of the 

country seeking consideration to be involved in the petitioning and data submittal 

process, and sought comment on whether participation by a foreign government should 

be specifically required. Commenters generally supported requiring the national 

government’s involvement in providing and/or verifying the data used in both the initial 

petition and in the annual reassessments, but most did not believe that the national 

government itself needed to be the petitioner. EPA agrees that, in order to ensure a 

robust and credible data set and analysis, the national government of the country from 

which the petition is submitted should be involved in the petition process and the annual 

validation, but need not be the party actually submitting the petition. Thus, in today’s 

final rule, EPA is requiring that the appropriate ministry or department within the 

national government submit a letter confirming that they have reviewed and verified the 

petition and the data supporting it, and that the data support a finding that planted crops 

and crop residue from the country meet the definition of renewable biomass and will 

continue to do so. Furthermore, EPA is requiring that the responsible national 

government ministry or department will review and verify the data submitted on an 

annual basis to facilitate EPA’s annual evaluation of the 2007 baseline area of land in that 

country. 
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Additionally, EPA indicated in the preamble to the proposed rule that it intended 

to 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. Commenters generally agreed that data used to 

support a petition must be publicly available and transparent. EPA agrees that this is 

highly preferable, so EPA will consider this factor in determining whether to grant a 

petition. Several commenters suggested that complete transparency requires the data 

itself as well as the data analysis conducted and methodology used by the petitioner to be 

made available to the public. EPA agrees that information that is not privileged should 

be made publicly available, and will publish petitioners’ data sources, statistical 

methodologies and analyses in the public rulemaking docket as part of the public notice 

and comment process to the extent permissible by law (see below for a more detailed 

description of the public participation process). 

EPA also proposed to 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 country. EPA believes that the data and analyses used for 

the annual assessments of any approved aggregate compliance approach must be just as 

robust and transparent as the data used to establish the original baseline amount of 

agricultural land. Some commenters argue that the national government should be 
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required to play a role in the ongoing land use tracking. As described above, EPA 

believes it is important to have the involvement of the national government in reviewing 

the data and analyses for the annual assessments. Other commenters argue that the 

annual verification should be conducted wholly by an independent third party to ensure 

accuracy and objectively. EPA has addressed these comments in Section V.B.4. below. 

Furthermore, EPA proposed to 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. We also proposed that petitioners submit historical land use data 

for the land in question, such as satellite data, aerial photography, census data, 

agricultural surveys or agricultural economic modeling data. EPA did not receive 

specific comments on the consideration of agricultural land use trends or on the 

requirement to submit data on historical land use trends. EPA believes that this 

information would be useful in assessing whether the 2007 baseline area of land would 

likely be exceeded in the future. Thus, as explained further in Section V.B.4 below, EPA 

is finalizing that, when evaluating petitions, we will take into consideration historical 

agricultural land use trends in the country in question, and we are requiring that 

petitioners submit historical land use data for the land in question. 

Finally, EPA proposed to consider whether there are laws in place in the country 

for which the petition was submitted that might prohibit or incentivize the clearing of 

new agricultural lands, and proposed to consider the efficacy of these laws. EPA also 
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proposed to assess whether any market factors are expected to drive an increase in the 

demand for agricultural land in the country for which the petition was submitted. 

Commenters generally supported EPA’s consideration of these factors when evaluating 

petitions, and thus EPA will take them into account when assessing petitions. For further 

discussion of this issue, see Section V.B.4 which follows. 

4. Petition Submission 

EPA proposed a requirement that all submittals, including the petition, supporting 

documentation, and annual data and analyses, be submitted in English. One commenter 

argued that the components of the petition should be submitted both in English and in the 

original language. We agree that it would be useful and reasonable for EPA to receive 

and make available to the public the petition and all supporting documents in English and 

their original language (if not English) in order to verify translation, particularly of 

technical texts and data. Therefore we are finalizing a requirement that all petitions and 

supporting documentation should be submitted in English and their original language. 

EPA also proposed that petitioners submit specified information as part of their 

formal petition submission package, or explain why such information is not necessary for 

EPA to consider their petition. EPA is finalizing the list of information that will be 

required, absent an explanation by the petitioner as to why any of the information is not 
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necessary, with modifications to reflect that petitions will be considered only for all 

planted crops and crop residue from foreign countries in their entirety. 

First, petitioners will need to submit an assessment of the total amount of land 

that is cropland, pastureland, or land equivalent to USDA’s Conservation Reserve 

Program land 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. 

As part of the assessment, the petitioner will be required to submit to EPA land 

use data that demonstrates that the proposed 2007 baseline area of land 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. The data may include satellite imagery 

or 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 farmlevel 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 National Agricultural 

Statistics Service (NASS) Crop Data Layer (CDL), which is based on satellite data. 
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 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 Conservation Reserve Program 

(CRP)29 land. In the proposal, EPA recognized that the CRP is only applicable to U.S. 

agricultural land, and thus solicited comment on whether the final rules should allow 

EPA to consider land that is equivalent or similar to US CRP land as existing agricultural 

land for purposes of RFS2-compliant feedstock cultivation in a foreign county, and 

whether EPA should be able to make such a determination in the context of a petition for 

application of the aggregate approach to a foreign country. Commenters noted that EPA 

should consider foreign land categories similar to CRP. EPA agrees, and has modified 

the final regulation to include specific references to “land that is equivalent to U.S. 

Conservation Reserve Program” land. One commenter also suggested that EPA consider 

lands falling outside of the definition of “existing agricultural land,” including degraded 

land and land not under primary forest. However, EPA disagrees that the types of land 

considered should extend beyond those that are equivalent to the land types identified in 

the final RFS2 definition of “existing agricultural land.” If the land in question does not 

meet the RFS2 definitions of “cropland” or “pastureland” in 40 CFR 80.1401, or it is not 

equivalent to CRP land, then it is not “existing agricultural land” from which crops or 

crop residue that meet the definition of “renewable biomass” can be obtained. 

Therefore, they will not be counted towards the total amount of existing agricultural land 

in a petition for application of the aggregate approach to a foreign country. 

 

29 The CRP program is administered by U.S. Department of Agriculture’s Farm Service Agency and 

provides technical and financial assistance to eligible farmers and ranchers to address soil, water, and 

related natural resource concerns on their lands in an environmentally beneficial and cost-effective manner. 
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Second, EPA proposed that the petitioner would also be required to provide to 

EPA historical land use data, 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 trend of contraction of 

agricultural land utilization in the U.S. Commenters generally supported this 

requirement. EPA believes that this will be useful information in considering the 

likelihood that the 2007 baseline area of land is likely to be exceeded in the future, and is 

finalizing a requirement that petitioners submit historical land use data as part of their 

petition. 

Third, EPA proposed that 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 agricultural land use within the foreign country. 

For the U.S. aggregate compliance approach determination, EPA took into account the 

CAA 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. Commenters supported the relevance of this type of 

information to EPA’s action on a petition for application of the aggregate approach to a 

foreign country. Furthermore, another commenter recommended that EPA consider the 

efficacy and enforcement of any applicable laws that may have an effect on the use of the 
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land in question. EPA agrees, and has modified this element in the final rule to require 

the submission of information regarding the efficacy and enforcement of relevant laws. 

One commenter suggested that EPA take into consideration the limitations on 

feedstock growth posed by local climate and soil quality. EPA understands that in some 

circumstances poor soil quality could be a factor that influences land use practices and, in 

particular, whether existing croplands continue to be used for crop production as opposed 

to former forestland. One of the factors identified for EPA consideration in today’s rule 

is whether historical land use and agricultural practices and/or other factors show that it is 

likely that producers will continue to use agricultural land within the 2007 baseline area 

of land. In addition, one of the required submission elements is “agricultural practices, 

economic considerations or other relevant factors that had or may have an effect on the 

use of agricultural land.” Thus, EPA believes that the considerations raised by the 

commenter can and will be considered by EPA in evaluating petition submittals. EPA 

urges the commenter to participate in the public notice and comment process that all 

petitions submitted to EPA will be subject to (see discussion of this subject in Section 

V.B.5), and to provide any information on these issues that the commenter believes may 

be appropriate for EPA evaluation at that time. 

 Among the "other relevant factors" that a petitioner must consider, there are a 

variety of environmental conditions or circumstances that may be relevant. For instance: 

• Local variability in weather 
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• Availability and quality of fresh water as supplied by snow pack, rain, 

runoff and inundations 

• Frost and icing 

• Severe winds and fires 

• Hail and sleet 

• Extended periods of rain or drought 

• Other extreme events 

Predictions on the seasonal to interannual (El Nino/La Nina) are available to improve the 

information included in the petition. Weather and water predictions may also be 

important for shorter term supply management and volume production analyses. 

Finally, EPA proposed and is finalizing that the petitioner be required to provide a 

plan describing an 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. Additionally, EPA proposed that the plan 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. One commenter argued that the annual verification should be 

conducted or reviewed by an independent third party financed by the petitioner through 

an escrow account. EPA believes that review of the initial and annual data by a qualified 

independent third party would add credibility and reliability to the process, but does not 

believe it should be required. EPA believes that providing notice through the Federal 

Register and opportunity for public comment on each petition submitted afford the public 
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ample time to analyze and comment on the data submitted by the petitioner. 

Furthermore, EPA is adding a requirement, described above, for participation in the 

process by the national government of the country for which a petition is submitted, and 

EPA will thoroughly scrutinize the information submitted in the petition prior to making 

any assessment. Therefore, EPA is not finalizing a requirement that the petition and the 

annual updates be analyzed by an independent third party, but EPA is reiterating that 

participation by an independent third party would add credibility to a petition and to 

annual evaluations. 

5. Petition Process

EPA proposed to provide an opportunity for public comment on petitions for 

approval of an aggregate compliance approach for a foreign country. EPA proposed to 

publish a Federal Register notice informing the public of incoming petitions, with 

information on how to view the petitions and any supporting information. Additionally, 

EPA proposed to then accept public comment on the petition. Once the public comment 

period closes, EPA proposed to make an assessment, taking into account the information 

submitted in the petition as well as the comments received, and then publish a decision in 

the Federal Register to either approve or deny the petitioner’s request. 

EPA proposed that, if the petition has been approved, the Federal Register notice 

will specify an effective date at which time producers using the specified feedstocks from 
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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 otherwise 

applicable individualized renewable biomass recordkeeping and reporting requirements. 

For the final rule, EPA has made a minor modification to the regulatory language in 40 

CFR 80.1454(g) to clarify the recordkeeping requirements from which renewable fuel 

producers are exempted if their feedstocks are subject to the aggregate compliance 

approach. Producers using feedstocks subject to the aggregate compliance approach are 

exempted from the renewable biomass recordkeeping requirements in 40 CFR 

80.1454(g)(2), but remain subject to the recordkeeping requirements related to feedstocks 

in 40 CFR 80.1454(b). 

EPA sought and received comments on this proposed petition process. Most 

commenters agree that each petition submitted should be subject to public notice and 

comment procedures. Several commenters argued that although there should be a public 

notice and comment period, it should not cause undue delays in reviewing and publishing 

a decision on the petitions. One commenter requested that 60 days be provided for public 

review of the incoming petitions. Another commenter also requested that EPA specify a 

timeline for the public comment process and the types of issues that will be addressed 

during the process. 

EPA agrees that public notice and comment is necessary and important, and is 

maintaining that process in today’s final rule. Furthermore, EPA intends that decisions 

on petitions will be made within an amount of time that is reasonable, yet sufficient to 

conduct a thorough analysis of the incoming data. EPA concurs that 60 days is a 
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reasonably practical amount of time for public review and analysis of the petition and 

associated data, so today’s rule provides for a 60 day comment period on each petition 

submitted. 

EPA does not agree with the comment that the public comments should be 

restricted to certain issues. EPA will evaluate all comments received to determine if they 

are relevant to its determination. The petitions and the supporting data will be included 

in the rulemaking docket in their entirety (excepting only material that is claimed to be 

confidential business information or which is otherwise privileged), and the public may 

comment on any aspect of the petitions or the supporting information. 

A commenter argued that the public notice and comment procedure should be 

included in the regulatory language, and that any and all data and calculations in the 

petitions should be available to the public. EPA generally agrees, and has included 

provisions concerning public notice and comment in the final regulatory language. 

Furthermore, EPA will make available in the docket all information submitted in support 

of each petition unless the material is claimed to be confidential business information or 

is otherwise legally prohibited from disclosure. 

Additionally, EPA proposed three circumstances that could lead EPA to withdraw 

its approval of the aggregate compliance approach for a foreign country. We received 

one comment that argued that EPA must withdraw its approval under the three 

circumstances identified in the proposed regulations at §80.1457(e)(1)(i)-(iii). Although 
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we generally agree that the three circumstances identified will likely lead EPA to 

withdraw its approval, we believe it is best to allow EPA the discretion to evaluate these 

circumstances on a case-by-case basis. Therefore, we have retained in the final rule the 

provision stating that EPA “may” withdraw its approval in the circumstances identified, 

in which case producers using planted crops or crop residue from the country in question 

would be subject to the individual recordkeeping and reporting requirements under 

§§80.1454(g) and 80.1451(d) beginning July 1 of the following year. 

Finally, EPA requested comment on whether the burden associated with the 

proposed petition process is reasonable, and how it might be minimized while still 

remaining adequately robust. One commenter noted that the burden of the petition 

process is reasonable as proposed, and could be made more stringent while remaining 

reasonable. EPA believes the level of burden associated with the proposed petition 

process was reasonable and appropriate and believes that the requirements set forth in 

today’s final rule do not significantly alter the proposed level of burden.
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VI. Annual Administrative Announcements 

 In the RFS2 final rule, we 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 applicable volume specified in the Clean Air 

Act (CAA), and 

• Announce the results of our annual assessment of the aggregate 

compliance approach for U.S. planted crops and crop residue. 

The biofuel waiver credit price being announced today was calculated in accordance with 

the specifications in §80.1456(d). Since the manner in which EPA calculates the waiver 

credit price is precisely set forth in EPA regulations (which were issued through a noticeand-comment process), and since some of the variables necessary to compute the price 

have only recently become available, EPA did not propose a waiver credit price for 

comment. Similarly, because EPA’s assessment of the aggregate compliance approach 

announced today was conducted using data sources, methodology, and criteria that were 

identified and explained in the preamble to the RFS2 final rule, it was not necessary to 

present a preliminary annual assessment for comment in the NPRM. 
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A. 2011 Price for Cellulosic Biofuel Waiver Credits 

Section 211(o)(7)(D) of the CAA requires that whenever EPA sets the applicable 

volume of cellulosic biofuel at a level lower than that specified in the Act, EPA is to 

provide a number of cellulosic credits for sale that is no more than the EPA-determined 

applicable volume. Congress also specified the formula for calculating the price for such 

waiver credits: adjusted for inflation, the credits must be offered at the price of the higher 

of 25 cents per gallon or the amount by which $3.00 per gallon exceeds the average 

wholesale price of a gallon of gasoline in the United States.30 The inflation adjustment is 

for years after 2008. EPA regulations provide that the inflation adjustment is calculated 

by comparing the most recent Consumer Price Index for Al Urban Consumers (CPI-U) 

for the “All Items” expenditure category as provided by the Bureau of Labor Statistics 

that is available at the time EPA sets the cellulosic biofuel standard to the comparable 

value that was reported soonest after December 31, 2008.31 

In contrast to its directions to EPA for setting the price of a cellulosic biofuel 

waiver credit, Congress afforded the Agency considerable flexibility in designing 

regulations specifying the permissible uses of the credits. The CAA states that EPA 

regulations “shall include such provisions, including limiting the credits’ uses and useful 

 

30 More information on wholesale gasoline prices can be found on the Department of Energy's (DOE), 

Energy Information Administration's (EIA) Web site at: 

http://tonto.eia.doe.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=A103B00002&f=M

31 See U.S. Department of Labor, Bureau of Labor Statistics (BLS), Consumer Price Index Web site at: 

http://www.bls.gov/cpi/ 
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life, as the Administrator deems appropriate to assist market liquidity and transparency, 

to provide appropriate certainty for regulated entities and renewable fuel producers, and 

to limit any potential misuse of cellulosic biofuel credits to reduce the use of other 

renewable fuels, and for such other purposes as the Administrator determines will help 

achieve the goals of this subsection.” The final RFS2 provides a detailed discussion of 

how we designed the provisions for cellulosic biofuel waiver credits in keeping with the 

statutory language. In short, 2011 cellulosic biofuel waiver credits (or ”waiver credits”) 

are only available for the 2011 compliance year. Waiver credits will only be made 

available to obligated parties, and they are nontransferable and nonrefundable. Further, 

obligated parties may only purchase waiver credits up to the level of their cellulosic 

biofuel RVO less the number of cellulosic biofuel RINs that they own. A company 

owning cellulosic biofuel RINs and cellulosic waiver credits may use both types of 

credits if desired to meet their RVOs, but unlike RINs obligated parties are not permitted 

to carry waiver credits over to the next calendar year. Obligated parties may not use 

waiver credits to meet a prior year deficit obligation. Finally, unlike cellulosic biofuel 

RINs which may also be used to meet an obligated party's advanced and total renewable 

fuel obligations, waiver credits may only be used to meet a cellulosic biofuel RVO. An 

obligated party will still need to additionally and separately acquire RINs to meet their 

advanced biofuel and total renewable fuel obligations. 

For the 2011 compliance period, since the applicable volume of cellulosic biofuel 

used to set the annual cellulosic biofuel standard is lower than the volume for 2011 

specified in the CAA, we are making cellulosic waiver credits available to obligated 
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parties for end-of-year compliance should they need them at a price of $1.13 per gallonRIN. To calculate this price, EPA first determined the average wholesale (refinery gate) 

price of gasoline using the most recent 12 months of data available from the EIA website 

on September 30, 2010. Based on this data, we calculated an average price of gasoline 

for the period July 2009 to June 2010 of $1.97. In accordance with the Act, we then 

calculated the difference of the inflation-adjusted value of $3.00, or $3.10, and $1.97, 

which yielded $1.13. Next, we compared the value of $1.13 to the inflation-adjusted 

value of $0.25, or $0.26. The Act requires EPA to use the greater of these two values as 

the price for cellulosic biofuel waiver credits. 

The derivation of this value is more fully explained in a memorandum submitted 

to the docket for this rulemaking,32 and a more complete description of the statutory 

requirements and their application can be found in the RFS2 final rule.33 The price for 

the 2012 compliance period, if necessary, will be set when we announce the 2012 

cellulosic biofuel standard. 

B. Assessment of the Domestic Aggregate Compliance Approach 

In order to implement the renewable biomass requirements under the RFS2 

program as set forth in the CAA, EPA established general requirements for renewable 

 

32 See memo to docket number EPA-HQ-OAR-2010-0133 from Scott Christian, on the subject of 

“Calculating the price for cellulosic biofuel waiver credits for compliance year 2011,” dated October 20, 

2010. 

33 75 FR 14726 - 14728 
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fuel producers to keep records on the types and feedstocks they use to produce their fuel, 

including specific records related to the land from which the feedstocks were harvested or 

otherwise obtained, if they generate RINs for the fuel produced from such feedstocks. 

We also established requirements for renewable fuel producers to report on their 

feedstocks on a quarterly basis. Similar requirements apply to importers who generate 

RINs for fuel produced outside of the U.S. 

In response to comments we received on the RFS2 NPRM, we also finalized a 

separate approach for renewable fuel producers who use planted crops and crop residue 

from U.S. agricultural land. Producers who use such renewable biomass need not 

maintain documentation about the specific land from which the feedstocks are harvested, 

relieving them of the individual recordkeeping and reporting requirements. To enable 

this approach, EPA established a baseline number of acres for U.S. agricultural land in 

2007 (the year of EISA enactment) and determined that as long as this baseline number 

of acres was not exceeded, it was unlikely that new land outside of the 2007 baseline 

would be devoted to crop production based on historical trends and economic 

considerations. We therefore provided that renewable fuel producers using planted crops 

or crop residue from the U.S. as feedstock in renewable fuel production need not comply 

with the individual recordkeeping and reporting requirements related to documenting that 

their feedstocks are renewable biomass, unless EPA determines through annual 

evaluations that the 2007 baseline acreage of agricultural land has been exceeded. 
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In the final RFS2 regulations, we stated that EPA will make a finding concerning 

whether the 2007 baseline amount of U.S. agricultural land has been exceeded in a given 

year and will publish this finding in the Federal Register by November 30 of the same 

year. If the baseline is found to have been exceeded, then producers using U.S. planted 

crops and crop residue as feedstocks for renewable fuel production would be required to 

comply with individual recordkeeping and reporting requirements to verify that their 

feedstocks are renewable biomass. We also stated that if, at any point, EPA finds that the 

total agricultural land is greater than 397 million acres, EPA will conduct further 

investigations regarding the validity of the aggregate compliance approach. 

Based on data provided by the USDA Farm Service Agency (FSA) and Natural 

Resources Conservation Service (NRCS), we have estimated that U.S. agricultural land 

reached approximately 398 million acres in 2010, and thus did not exceed the 2007 

baseline acreage.34 However, this total acreage estimate is greater than the 397 million 

acre trigger point for further investigation, therefore EPA, with the help of USDA, will 

look further into the relevant data and review the factors related to U.S. agricultural land 

use over the coming months. 

The data and methodologies employed to make this determination are described 

below. 

 

34 See memo to docket number EPA-HQ-OAR-2010-0133 from Megan Brachtl, on the subject of “USDA 

data used for 2010 U.S. agricultural land determination,” dated November 9, 2010. 
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1. Methodology

To set the 2007 baseline acreage for U.S. agricultural land in the RFS2 final 

rulemaking, we used USDA’s Farm Service Agency’s (FSA’s) crop history data for 

2007, which was the most complete, consistent, and reliable dataset available to EPA. 

From the FSA crop history data total acreage of 404.3 million acres, we subtracted 2.75 

million acres, which represented the amount of land enrolled in USDA’s Grasslands 

Reserve Program (GRP) and Wetlands Reserve Program (WRP), neither of which 

qualifies as existing agricultural land. We therefore established the 2007 baseline amount 

of existing U.S. agricultural land at 402 million acres. This is the amount of land we 

determined was available for the production of planted crops and crop residue in 2007 

that would satisfy the renewable biomass provisions of the CAA. 

To calculate the 2010 U.S. agricultural land acreage estimate, we followed a 

similar calculation methodology. We started with FSA crop history data for 2010, from 

which we derived a total estimated acreage of 401.6 million acres. We then subtracted 

the amount of land estimated to be participating in the GRP and WRP by the end of 

Fiscal Year 2010, 3.6 million acres, to yield an estimate of approximately 398.0 million 

acres of U.S. agricultural land in 2010. The USDA data used to make this calculation can 

be found in the docket to this rule. 

In the preamble to the final RFS2 rule, we indicated that we would monitor total 

U.S. agricultural land annually using FSA crop history data as a primary determinant and 
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USDA’s satellite-based crop data layer (CDL) analyses as a secondary source to validate 

our annual assessment. The CDL data for 2009 were released at the beginning of 2010, 

and the CDL data for 2010 is similarly expected in early 2011. Because the schedule for 

the release of 2010 data falls after the date by which the RFS2 regulations state the 

annual U.S. agricultural land acreage determination must be made, we will use the 2009 

and 2010 data, as appropriate and feasible, to validate our 2010 assessment, as discussed 

below. 

2. Further Investigation

EPA stated in the final RFS2 rule that if we find that the total land used for the 

production of crops is greater than 397 million acres, we will conduct further 

investigations regarding the validity of the aggregate compliance approach. Because we 

estimate that total U.S. agricultural land acreage in 2010 was approximately 398 million 

acres, further inquiry into the aggregate compliance approach is warranted. This inquiry, 

to be carried out by EPA with assistance from USDA, will utilize other agricultural data, 

including USDA’s 2009 and 2010 CDL data to the extent feasible, to validate the data 

used to make the U.S. agricultural land determination for 2010. We will also consider 

potential uncertainties in the data used to make our determination. We anticipate that this 

investigation will be completed well before the deadline for publishing next year’s 

agricultural land acreage determination. 
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VII. Comments Outside the Scope of This Rulemaking 

 In their comments responding to the NPRM, a number of parties used the 

opportunity to raise concerns that were not directly related to the issues and provisions 

we were addressing in the NPRM, such as setting the cellulosic biofuel standard, the 

proposed provision for delayed RINs, and the proposed provision for aggregate 

compliance for renewable biomass from foreign countries. Neither did these comments 

address setting the price for cellulosic biofuel credits or EPA’s annual evaluation of the 

U.S. aggregate compliance approach for renewable biomass. Instead, they addressed 

issues associated with the following: 

· EPA’s petition process in §80.1416 for approving new fuel pathways 

· EPA’s ongoing lifecycle GHG assessment for grain sorghum 

· EPA’s economic analyses related to expanded biofuels use and the impact 

of tax credits and tariffs 

· Possible legislative amendments and possible EPA actions favored by 

commenters that would promote biofuel use 

Some commenters also made requests for clarification of key definitions while others 

suggested modifications to the provisions regarding the use of cellulosic biofuel waiver 
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credits. While we are taking these comments under consideration as we continue to 

implement the RFS2 program, these comments are outside the scope of today’s action, 

and we are not providing substantive responses to them at this time. 
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VIII. Public Participation 

 Many interested parties participated in the rulemaking process that culminates 

with this final rule. This process provided opportunity for submitting written public 

comments following the proposal that we published on July 20, 2010 (75 FR 42238), and 

we considered these comments in developing the final rule. Comments and responses for 

issues raised in the public comments are included throughout this preamble. 
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IX. 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 sets the percentage 

standards applicable in 2011 based on the volumes that were analyzed in the RFS2 final 

rule or, for cellulosic biofuel, on a lower volume that reflects EPA’s projection of 

cellulosic biofuel production volumes for 2011. The delayed RINs provision and the 

petition process for applying an aggregate approach to foreign-grown crops and crop 

residue have no adverse economic impact on regulated parties since they would either 

relieve a current restriction related to generation of RINs, or would reduce recordkeeping 

burdens for parties successfully utilizing the petition process. The announcement of 

cellulosic biofuel waiver credit price and EPA’s annual assessment of the U.S. aggregate 

compliance approach also impose no adverse economic impact. The availability of 
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cellulosic biofuel waiver credits provides increased flexibility to regulated parties, at a 

price established by a formula set forth in the CAA. 

B. Paperwork Reduction Act 

 

This rule contains new information collection requirements which will be 

submitted for approval to the Office of Management and Budget (OMB) under the 

Paperwork Reduction Act, 44 U.S.C. 3501 et seq. These information collection 

requirements are not enforceable until OMB approves them. The EPA ICR number 

2398.02. 

Specifically, this rule has a petition provision that EPA will 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 may petition EPA for approval 

of the aggregate compliance approach for crops and crop residue in a foreign country. If 

approved by EPA, such a petition will allow crops and crop residue produced in the 

foreign country to be counted as feedstock to make renewable fuel under the RFS2 

program without the otherwise applicable recordkeeping requirements. Other provisions 

in this regulation will not impose any new information collection burdens on regulated 

entities beyond those already required under RFS2. The RFS2 information collections 
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are identified by the following OMB control numbers: 2060-0637 (expiring March 31, 

2013) and 2060-0640 (expiring July 31, 2013). 

The information collection related to this final rule 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 will characterize the information they submit to us under this 

information collection as CBI. However, any information claimed as confidential will 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 will be a total of 15 respondents (petitioners), each 

submitting one petition, for a total of 15 responses (petitions). The estimated burden 

annual burden, assuming 15 respondents, will be 200 hours and annual cost is estimated 

at $14,197. On a per respondent basis, EPA estimates a total annual hour burden per 

respondent of 13.33 hours and a total annual cost burden per respondent is $946.43. 

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. 
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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-forprofit enterprise which is independently owned and operated and is not dominant in its 

field. 

 After considering the economic impacts of today’s rule on small entities, we 

certify that this action will not have a significant economic impact on a substantial 

number of small entities. This rule sets the annual standards for four types of renewable 

fuel, modifies the regulatory provision for the generation of delayed RINs, and 

establishes a process for parties to petition EPA to allow an aggregate approach to 
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compliance with the renewable biomass provision for foreign-grown crops and crop 

residue that would be similar to that used in the U.S. Today’s action also includes two 

administrative announcements: The price in 2011 for cellulosic biofuel waiver credits, 

and the results of EPA’s annual assessment of the U.S. aggregate compliance approach. 

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), and today’s action does not 

impose any additional requirements or burdens on small entities. 

 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 
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This 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. 

 

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 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 
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 EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying only to those 

regulatory actions that concern health or safety risks, such that the analysis required 

under section 5-501 of the EO has the potential to influence the regulation. This action is 

not subject to EO 13045 because it does not establish an environmental standard intended 

to mitigate health or safety risks and because it implements specific standards established 

by Congress in statutes. 

H. Executive Order 13211: Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use 

 This rule is not a “significant energy action” as defined in Executive Order 13211, 

“Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, 

or Use” (66 FR 28355 (May 22, 2001)) because it is not likely to have a significant 

adverse effect on the supply, distribution, or use of energy. 

I. National Technology Transfer Advancement Act 

 Section 12(d) of the National Technology Transfer and Advancement Act of 1995 

(“NTTAA”), Public Law No. 104-113, 12(d) (15 U.S.C. 272 note) directs EPA to use 

voluntary consensus standards in its regulatory activities unless to do so would be 

inconsistent with applicable law or otherwise impractical. Voluntary consensus standards 
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are technical standards (e.g., materials specifications, test methods, sampling procedures, 

and business practices) that are developed or adopted by voluntary consensus standards 

bodies. NTTAA directs EPA to provide Congress, through OMB, explanations when the 

Agency decides not to use available and applicable voluntary consensus standards. 

 This action does not involve technical standards. Therefore, EPA 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 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 
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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. 

K. Congressional Review Act

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a 

rule may take effect, the agency promulgating the rule must submit a rule report, which 

includes a copy of the rule, to each House of the Congress and to the Comptroller 

General of the United States. EPA will submit a report containing this rule and other 

required information to the U.S. Senate, the U.S. House of Representatives, and the 

Comptroller General of the United States prior to publication of the rule in the Federal 

Register. A major rule cannot take effect until 60 days after it is published in the Federal 

Register. This action is not a “major rule” as defined by 5 U.S.C. 804(2) and therefore it 

is not subject to the Congressional Review Act. Therefore, this rule will be effective on 

the date of publication. 
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X. Statutory Authority 

Statutory authority for the rule finalized today can be found in section 211 of the 

Clean Air Act, 42 U.S.C. 7545. Additional support for the procedural and compliance 

related aspects of today's rule, including the recordkeeping requirements, come from 

Sections 114, 208, and 301(a) of the Clean Air Act, 42 U.S.C. Sections 7414, 7542, and 

7601(a). 

 

List of Subjects in 40 CFR Part 80 

Environmental protection, Air pollution control, Diesel Fuel, Fuel additives, Forest and 

forest products, Gasoline, Oil imports, Labeling, Motor vehicle pollution, Penalties, 

Petroleum, Reporting and recordkeeping requirements. 

Dated: 

Lisa P. Jackson, 

Administrator. 
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For the reasons set forth in the preamble, 40 CFR part 80 is 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 80.1405 is amended by revising paragraph (a) to read as follows: 

§ 80.1405 What are the Renewable Fuel Standards? 

(a) Renewable Fuel Standards for 2011.

(1) The value of the cellulosic biofuel standard for 2011 shall be 0.003 

percent. 

(2) The value of the biomass-based diesel standard for 2011 shall be 0.69 

percent. 

(3) The value of the advanced biofuel standard for 2011 shall be 0.78 percent. 

(4) The value of the renewable fuel standard for 2011 shall be 8.01 percent. 

* * * * * 
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3. Section 80.1426 is amended by revising 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?

* * * * * 

(g) Delayed RIN generation. 

(1) Parties who produce or import renewable fuel may elect to generate 

delayed RINs to represent renewable fuel volumes that have already been 

transferred to another party if those renewable fuel volumes meet all of the 

following requirements. 

(i) The renewable fuel volumes can be described by a new pathway 

that has been added to Table 1 to §80.1426, or approved by 

petition pursuant to §80.1416, after July 1, 2010. 

(A) For new pathways that EPA approves in response to 

petitions submitted pursuant to §80.1416, complete 

petitions must be received by EPA by January 31, 2011. 
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(B) [Reserved] 

(ii) The renewable fuel volumes can be described by a pathway that: 

(A) Is biodiesel that is made from canola oil through 

transesterification using natural gas or biomass for process 

energy; or 

(B) EPA has determined was in use as of July 1, 2010, for the 

primary purpose of producing transportation fuel, heating 

oil, or jet fuel for commercial sale. 

(iii) The renewable fuel volumes were not designated or intended for 

export from the 48 contiguous states plus Hawaii by the renewable 

fuel producer or importer, and the producer or importer of the 

renewable fuel volumes does not know or have reason to know that 

the volumes were exported from the 48 contiguous states plus 

Hawaii. 

(2) When a new pathway is added to Table 1 to §80.1426 or approved by 

petition pursuant to §80.1416, EPA will specify in its approval action the 

effective date on which the new pathway becomes valid for the generation 
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of RINs and whether the fuel in question meets the requirements of 

paragraph (g)(1)(ii) of this section. 

(i) The effective date for the pathway describing biodiesel that is 

made from canola oil through transesterification using natural gas 

or biomass for process energy is September 28, 2010. 

(ii) [Reserved] 

(3) Delayed RINs can only be generated to represent renewable fuel volumes 

produced in the 48 contiguous states plus Hawaii or imported into the 48 

contiguous states plus Hawaii between July 1, 2010, and the earlier of 

either of the following dates: 

(i) The effective date (identified pursuant to paragraph (g)(2) of this 

section) of the new pathway through which the fuel in question 

was produced; or 

 (ii) December 31, 2011. 

(4) Delayed RINs must be generated no later than 60 days after the effective 

date (identified pursuant to paragraph (g)(2) of this section) of the 

pathway by which the fuel in question was produced. 
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(5) A party authorized pursuant to paragraph (g)(1) of this section to generate 

delayed RINs, and electing to do so, who generated RINs pursuant to 

80.1426(f)(6) for fuel produced through a pathway described in paragraph 

(g)(1) of this section, and transferred those RINs with renewable fuel 

volumes between July 1, 2010 and the effective date (identified pursuant 

to paragraph (g)(2) of this section) of that pathway, must retire a number 

of gallon-RINs prior to generating delayed RINs. 

(i) The number of gallon-RINs retired by a party pursuant to this 

paragraph must not exceed the number of gallon-RINs originally 

generated by the party to represent fuel described in paragraph 

(g)(1) of this section that was produced in the 48 contiguous states 

plus Hawaii or imported into the 48 contiguous states plus Hawaii, 

and transferred to another party, between July 1, 2010 and the 

earlier of either of the following dates: 

(A) The effective date (identified pursuant to paragraph (g)(2) 

of this section) of the new pathway through which the fuel 

in question was produced; or 

(B) December 31, 2011. 

(ii) Retired RINs must have a D code of 6. 
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(iii) Retired RINs must have a K code of 2. 

(iv) Retired RINs must have been generated in the same year as the 

gallon-RINs originally generated by the party to represent fuel 

described in paragraph (g)(1) of this section. 

(A) For gallon-RINs originally generated in 2010 to represent 

fuel described in paragraph (g)(1) of this section, the 

generation year of retired RINs shall be 2010. 

(B) For gallon-RINs originally generated in 2011 to represent 

fuel described in paragraph (g)(1) of this section, the 

generation year of retired RINs shall be 2011. 

(6) For parties that retire RINs pursuant to paragraph (g)(5) of this section, the 

number of delayed gallon-RINs generated shall be equal to the number of 

gallon-RINs retired in accordance with paragraph (g)(5) of this section. 

(7) A party authorized pursuant to paragraph (g)(1) of this section to generate 

delayed RINs, and electing to do so, who did not generate RINs pursuant 

to §80.1426(f)(6) for renewable fuel produced in the 48 contiguous states 

plus Hawaii or imported into the 48 contiguous states plus Hawaii 

between July 1, 2010 and the effective date (identified pursuant to 
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paragraph (g)(2) of this section) of a new pathway for the fuel in question, 

may generate a number of delayed gallon-RINs for that renewable fuel in 

accordance with paragraph (f) of this section. 

(i) The standardized volume of fuel (Vs) used by a party to determine 

the RIN volume (VRIN) under paragraph (f) of this section shall be 

the standardized volume of the fuel described in paragraph 

(g)(1)(i) of this section that was produced in the 48 contiguous 

states plus Hawaii or imported into the 48 contiguous states plus 

Hawaii by the party, and transferred to another party, between July 

1, 2010 and the earlier of either of the following dates: 

(A) The effective date (identified pursuant to paragraph (g)(2) 

of this section) of the new pathway through which the fuel 

in question was produced; or 

(B) December 31, 2011. 

(ii) [Reserved] 

(8) The renewable fuel for which delayed RINs are generated must be 

described by a pathway that satisfies the requirements of paragraph (g)(1) 

of this section. 
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(9) All delayed RINs generated by a renewable fuel producer or importer 

must be generated within EMTS on the same date. 

(10) The generation year of delayed RINs as designated in EMTS shall be the 

year that the renewable fuel volumes they represent were either produced 

or imported into the 48 contiguous states plus Hawaii. 

(i) For renewable fuel volumes produced or imported in 2010, the 

generation year of delayed RINs shall be 2010 and the production 

date specified in EMTS shall be 07/01/2010. 

(ii) For renewable fuel volumes produced or imported in 2011, the 

generation year of delayed RINs shall be 2011 and the production 

date specified in EMTS shall be 01/01/2011. 

(11) Delayed RINs shall be generated as assigned RINs in EMTS with a batch 

number that begins with "DRN", and then immediately separated by the 

RIN generator. 

(12) The D code that shall be used in delayed RINs shall be the D code which 

corresponds to the new pathway. 
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(13) Except as provided in this paragraph (g), all other provisions in this 

Subpart M that pertain to the identification of fuels for which RINs may 

be generated, the generation and use of RINs, and recordkeeping and 

reporting, are also applicable to delayed RINs. 

4. Section 80.1454 is amended as follows: 

a. By revising paragraph (g) introductory text. 

b. By revising paragraph (g)(1). 

c. By revising paragraph (g)(2) introductory text. 

§ 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 from 

planted crops or crop residue from existing agricultural land in a country covered 

by a petition approved pursuant to §80.1457, is covered by the aggregate 
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compliance approach and is not subject to the recordkeeping requirements for 

planted crops and crop residue at §80.1454(g)(2) unless EPA publishes a finding 

that the 2007 baseline amount of agricultural land in the U.S. has been exceeded 

or, for the aggregate compliance approach in a foreign country, that the 

withdrawal of EPA approval of the aggregate compliance approach is warranted 

pursuant to §80.1457(e). 

(1) EPA will make findings concerning whether the 2007 baseline amount of 

agricultural land in the U.S. or other country covered by a petition approved 

pursuant to §80.1457 has been exceeded and will publish these findings in the 

Federal Register by November 30 of the year preceding the compliance period. 

(2) If EPA finds that the 2007 baseline amount of agricultural land in the U.S. or 

other country covered by a petition approved pursuant to §80.1457 has been 

exceeded, beginning on the first day of July of the compliance period in question 

any producer or RIN-generating importer of renewable fuel made from planted 

crops or crop residue in the country for which such a finding is made must keep 

all the following records: 

* * * * * 

5. Section 80.1457 is added to read as follows: 
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§ 80.1457 Petition Process for Aggregate Compliance Approach for Foreign 

Countries 

 (a) EPA may approve a petition for application of the aggregate compliance approach 

to planted crops and crop residue from existing agricultural land in a foreign 

country if EPA determines that an aggregate compliance approach will provide 

reasonable assurance that planted crops and crop residue from the country in 

question 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 all of the following: 

(i) Whether there has been a reasonable identification of the “2007 

baseline area of land,” defined as the total amount of cropland, 

pastureland, and land that is equivalent to U.S. Conservation 

Reserve Program land in the country in question that was actively 

managed or fallow and nonforested on December 19, 2007. 

(ii) Whether information on the total amount of cropland, pastureland, 

and land that is equivalent to U.S. Conservation Reserve Program 

land in the country in question for years preceding and following 

calendar year 2007 shows that the 2007 baseline area of land 
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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 other factors show that it is 

likely that producers of planted crops and crop residue will 

continue to use agricultural land within the 2007 baseline area of 

land identified in paragraph (a)(1)(i) of this section into the future, 

as opposed to clearing and cultivating land not included in the 

2007 baseline area of land. 

(iv) Whether there is a reliable method to evaluate on an annual basis 

whether the 2007 baseline area of land identified in paragraph 

(a)(1)(i) of this section is being or has been exceeded. 

(v) Whether a credible and reliable entity has been identified to 

conduct data gathering and analysis, including annual 

identification of the aggregate amount of cropland, pastureland, 

and land that is equivalent to U.S. Conservation Reserve Program 

land, needed for the annual EPA evaluation specified in 

§80.1454(g)(1), and whether the data, analyses, and methodologies 

are publicly available. 

 (2) [Reserved] 

(b) Any petition and all supporting materials submitted under paragraph (a) of this 

section must be submitted both in English and its original language (if other than 
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English), and must include all of the following or an explanation of why it is not 

needed for EPA to consider 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) The total amount of land that is cropland, pastureland, or land equivalent 

to U.S. Conservation Reserve Program land 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 

 

(3) Land use data that demonstrates that the land identified in paragraph (b)(1) 

of this section is cropland, pastureland or land equivalent to U.S. 

Conservation Reserve Program 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 any of the following: 

 (i) Satellite imagery or data. 

 (ii) Aerial photography. 

 (iii) Census data. 

 (iv) Agricultural survey data. 

 (v) Agricultural economic modeling data. 
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(4) 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 or data. 

 (ii) Aerial photography. 

 (iii) Census data. 

 (iv) Agricultural surveys. 

 (v) Agricultural economic modeling data. 

(5) 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 agricultural land within the geographic boundaries specified in 

paragraph (b)(1) of this section, including information regarding the 

efficacy and enforcement of relevant laws and regulations. 

(6) A plan describing how the petitioner will identify a credible and reliable 

entity who will, on a continuing basis, conduct data gathering, analysis, 

and submittal to assist EPA in making an annual determination of whether 

the criteria specified in paragraph (a) of this section remains satisfied. 
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(7) A letter, signed by a national government representative at the ministerial 

level or equivalent, confirming that the petition and all supporting data 

have been reviewed and verified by the ministry (or ministries) or 

department(s) of the national government with primary expertise in 

agricultural land use patterns, practices, data, and statistics, that the data 

support a finding that planted crops and crop residue from the specified 

country meet the definition of renewable biomass and will continue to 

meet the definition of renewable biomass, and that the responsible national 

government ministry (or ministries) or department(s) will review and 

verify the data submitted on an annual basis to facilitate EPA’s annual 

evaluation of the 2007 baseline area of land specified in §80.1454(g)(1) 

for the country in question. 

(8) Any additional information the Administrator may require. 

(c) EPA will issue a Federal Register notice informing the public of receipt of any 

petition submitted pursuant to this section and will provide a 60–day period for 

public comment. 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 planted crops and crop residue from the 

country. Thereafter, the planted crops and crop residue from the country 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. 
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(d) If EPA grants a petition to establish an aggregate compliance approach for planted 

crops and crop residue from a foreign country, 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 compliance approach for 

the planted crops and crop residue from the country in question if: 

 (i) EPA determines that the data submitted pursuant to the plan 

described in paragraph (b)(6) of this section does not demonstrate 

that the amount of cropland, pastureland and land equivalent to 

U.S. Conservation Reserve Program land within the geographic 

boundaries covered by the approved petition does not exceed the 

2007 baseline area of land; 

(ii) EPA determines based on other information that the criteria 

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 for a given country, then producers using 

planted crops or crop residue from that country 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).