76790 Federal Register / Vol. 75, No. 236 / Thursday, December 9, 2010 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 80 

[EPA–HQ–OAR–2010–0133; FRL–9234–6] 

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 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 

December 9, 2010. 

ADDRESSES: EPA has established a 

docket for this action under Docket ID 

No. EPA–HQ–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 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; E-mail address: asdinfo@epa.gov. 

SUPPLEMENTARY INFORMATION: 

I. General Information 

A. Does this action apply to me? 

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 

SIC 2

codes Examples of potentially regulated entities 

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

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

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

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

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

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

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

1 North American Industry Classification System (NAICS). 

2Standard Industrial Classification (SIC) system code. 

This table is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

regulated by this 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 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 

III. Percentage Standards for 2011 

A. Background 

B. Calculation of Standards 

1. How are the standards calculated? 

2. Small Refineries and Small Refiners 


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1 75 FR 14670. 2 75 FR 59622. 

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 

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 

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 

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, 

2010.1 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 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. 

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. 

TABLE I.A–1—REQUIRED VOLUMES IN

THE CLEAN AIR ACT FOR 2011 

[Billion gal] 

Actual 

volume 

Ethanol 

equivalent 

volume 

Cellulosic biofuel ....... a 0.25 0.25 

Biomass-based diesel 0.80 1.20 

Advanced biofuel ...... 1.35 1.35 

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

aThis value assumes that all cellulosic 

biofuel would be ethanol. If any portion of the 

renewable fuel used to meet the cellulosic 

biofuel volume mandate has a volumetric energy content greater than that for ethanol, this 

value will be lower. 

By November 30 of each year, the EPA 

is required under CAA 211(o)(3)(B) to 

determine and publish in the Federal 


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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 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. 

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 ethanolequivalent 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. 

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 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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3The 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. 

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 nonrenewable 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 2011 3, 

there is no small refiner/refinery volume 

adjustment to the 2011 standard as there 

was for the 2010 standard. Thus, the 

increase in the percentage standards 

relative to 2010 appears smaller than 

would otherwise be the case, since more 

obligated parties will be participating in 

the program. The 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 

Percent 

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-of-year compliance 

should they need them at a price of 

$1.13 per credit. Further discussion is 

provided in Section VI.A. 

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 RIN-qualifying 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 domesticallygrown 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 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. 

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 


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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. 

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 ethanolequivalent 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 

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. 

Moreover, only a small percentage of the 

reports were both complete and correct 

upon initial submission, and about onefourth 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 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 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. 


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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. 

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 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. 

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 of 2.3 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 biocrude 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 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. 


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4Letter from Richard Newell, EIA Administrator 

to Lisa Jackson, EPA Administrator October 20, 

2010. 

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 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 pretreatment process followed by 

enzymatic hydrolysis to produce 

cellulosic ethanol from wheat, oat, and 

barley straw. They have a demonstration 

facility with an annual production 

capacity of 500,000 gallons of ethanol 

located in Ontario, Canada. This facility 

has been operational and producing 

small volumes of ethanol since 2004. So 

far all of the ethanol produced by this 

facility has been used locally and in 

racing and other promotional events. 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. 

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. 

TABLE II.A.3–1—EIA’S PROJECTED CELLULOSIC BIOFUEL PLANT PRODUCTION ESTIMATES FOR 2011 

Company name Location Feedstock Fuel Capacity 

(MGY) Facility status 

Expected 

utilization 

(Percent) 

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 

KL Energy .............. Upton, WY ............. Wood ..................... Ethanol .................. 1.5 Online .................... 10 0.15 

Range .................... Soperton, GA ........ Wood Waste ......... Methanol, Ethanol 4 Online .................... 25 1.0 

Total ............... ............................... ............................... ............................... ................ ............................... ................ 3.94 

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 


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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 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. 

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 

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

KiOR ...................... Houston, TX .......... Wood Waste ......... Diesel .................... 0.2 Online .................... 0.2 0.3 

Range .................... Soperton, GA ........ Wood Waste ......... Methanol, Ethanol 4 Online .................... 3.0 2.3 

Total ............... ............................... ............................... ............................... ................ ............................... 6.6 6.0 

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 enough so that any 

cellulosic biofuel that might be 

produced in 2011 in the U.S. 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: 

• For each of the facilities listed, with 

the exception of KiOR, we are projecting 

that their production will be some 


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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). 

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, 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 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 

1,206 million gallons of the 1,350 

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. 

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 .......................................................................................................................................... 13,950 13,500–13,549 

Conventional renewable fuel a ........................................................................................................................... 12,600 12,600 

Total advanced biofuel ...................................................................................................................................... 1,350 903–951 

Cellulosic biofuel ................................................................................................................................................ 6.0 6.6 

Biomass-based diesel ........................................................................................................................................ 1,200 800 

Other advanced biofuel b ................................................................................................................................... 144 c 96–144 

aPredominantly corn-starch ethanol. 

b Rounded to nearest million gallons for simplicity. 

cPhysical 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 


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

released 4/8/2010. 6Lundell, Drake, ‘‘Brazilian Ethanol Export Surge 

to End; U.S. Customs Loophole Closed Oct. 1,’’ 

Ethanol and Biodiesel News, Issue 45, November 4, 

2008. 7Renewable Fuels Association (RFA), ‘‘2008 

World Fuel Ethanol Production,’’ http:// 

www.ethanolrfa.org/pages/statistics#E, March 31, 

2009. 8EIA STEO, September 2010, Table 8. 

higher than what would be needed in 

2011. 

TABLE II.B–2—HISTORICAL IMPORTS

OF ETHANOL (MILL GALLONS) 5

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

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

2009 .......................................... 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. 

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 1,200 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. 

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 cornethanol, 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 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 cornethanol 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 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 


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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 

biomass-based 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. 

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-and-dash, 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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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 


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9Plant List from Biodiesel Magazine (http:// 

www.biodieselmagazine.com/plant-list.jsp.) 

10EIA Monthly Energy Review for August 2010, 

Table 10.4. 

11See 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. 

12Comments from National Biodiesel Board on 

the July 20, 2010 NPRM. Submitted to docket EPA– 

HQ–OAR–2010–0133 on August 19, 2010. 13Figures taken from National Biodiesel Board’s 

Member Plant List as of September 13, 2010. http:// 

biodiesel.org/buyingbiodiesel/plants/showall.aspx. 

14See Federal Register v.74 n.99 p.24903. 

Comments are available in docket EPA–HQ–OAR– 

2005–0161. 

15Project status updates are available via the 

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

wp-news/. 

operating is 2.4 billion gallons.9

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 document,11 EPA estimated that 

the 1.15 bill gal standard for biomassbased diesel in 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 biomassbased diesel did not exist in 2009, and 

the mandate for biomass-based 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 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 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 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 


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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 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. 

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. 

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): 


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16Letter from Richard Newell, EIA Administrator 

to Lisa Jackson, EPA Administrator. 

17To 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. 

Where: 

StdCB,i = The cellulosic biofuel standard for 

year i, in percent. 

StdBBD,i = The biomass-based diesel standard 

(ethanol-equivalent basis) for year i, in 

percent. 

StdAB,i = The advanced biofuel standard for 

year i, in percent. 

StdRF,i = The renewable fuel standard for year 

i, in percent. 

RFVCB,i = Annual volume of cellulosic 

biofuel required by section 211(o) of the 

Clean Air Act for year i, in gallons. 

RFVBBD,i = Annual volume of biomass-based 

diesel required by section 211(o) of the 

Clean Air Act for year i, in gallons. 

RFVAB,i = Annual volume of advanced 

biofuel required by section 211(o) of the 

Clean Air Act for year i, in gallons. 

RFVRF,i = Annual volume of renewable fuel 

required by section 211(o) of the Clean 

Air Act for year i, in gallons. 

Gi = Amount of gasoline projected to be used 

in the 48 contiguous states and Hawaii, 

in year i, in gallons. 

Di = Amount of diesel projected to be used 

in the 48 contiguous states and Hawaii, 

in year i, in gallons. 

RGi = Amount of renewable fuel blended into 

gasoline that is projected to be consumed 

in the 48 contiguous states and Hawaii, 

in year i, in gallons. 

RDi = Amount of renewable fuel blended into 

diesel that is projected to be consumed 

in the 48 contiguous states and Hawaii, 

in year i, in gallons. 

GSi = Amount of gasoline projected to be 

used in Alaska or a U.S. territory in year 

i if the state or territory opts-in, in 

gallons. 

RGSi = Amount of renewable fuel blended 

into gasoline that is projected to be 

consumed in Alaska or a U.S. territory in 

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

gallons. 

DSi = Amount of diesel projected to be used 

in Alaska or a U.S. territory in year i if 

the state or territory opts-in, in gallons. 

RDSi = Amount of renewable fuel blended 

into diesel that is projected to be 

consumed in Alaska or a U.S. territory in 

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

gallons. 

GEi = The amount of gasoline projected to be 

produced by exempt small refineries and 

small refiners in year i, in gallons, in any 

year they are exempt per §§ 80.1441 and 

80.1442, respectively. For 2011, this 

value is zero. See further discussion in 

Section III.B.2 below. 

DEi = The amount of diesel projected to be 

produced by exempt small refineries and 

small refiners in year i, in gallons, in any 

year they are exempt per §§ 80.1441 and 

80.1442, respectively. For 2011, this 

value is zero. See further discussion in 

Section III.B.2 below. 

The four separate renewable fuel 

standards for 2011 are based in part on 

the 49-state gasoline and diesel 

consumption volumes projected by EIA. 

The projected volumes 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, 2010.16 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 Congressionallymandated 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 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 biomassbased diesel standard based on biodiesel 

equivalence. However, all RIN 

generation is based on ethanolequivalence. More specifically, the 

RFS2 regulations provide that 

production or import of a gallon of 

biodiesel will lead to the generation of 

1.5 RINs. In order to ensure that demand 

for 0.8 billion physical gallons of 

biomass-based diesel will be created in 

2011, the calculation of the biomassbased diesel standard provides that the 

required volume be multiplied by 1.5 

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. 

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 

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. 


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TABLE III.B.1–2—PERCENTAGE

STANDARDS FOR 2011 

Percent 

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 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 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 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. 

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 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. 


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

Accessed at: http://www1.eere.energy.gov/biomass/ 

abcs_biofuels.html#content. 

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). 

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 

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

Fischer-Tropsch process.3 (cellulosic biofuel). 

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 FischerTropsch 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 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 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 

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, 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. 

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 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. 

BILLING CODE 6560–50–P 


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BILLING CODE 6560–50–C 


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

Advanced Biofuels Technologies.’’ Memo to the 

docket, November 17, 2010. 

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 

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 non-biogenic materials, would at 

best travel through the fuel production 

process unchanged, resulting in reduced 

fuel production capacity. Depending on 

the type of contaminant they may also 

be converted to undesired byproducts 

that must be separated from the fuel. 

They could also be toxic to the 

biological organisms being used to 

convert the sugars to fuel, necessitating 

a shut down and restart of the plant. 

Any of these scenarios would result in 

a significant cost to the fuel producer. 

Feedstocks such as agricultural 

residues, wood chips, or herbaceous or 

woody energy crops are likely to contain 

far fewer contaminants than more 

heterogeneous feedstocks such as 

municipal solid waste (MSW). 

b. Biomass Pretreatment 

The purpose of the biomass 

pretreatment stage is to disrupt the 

structure of the cellulosic biomass to 

allow for the hydrolysis of the cellulose 

and hemicellulose into simple sugars. 

The ideal pretreatment stage would 

allow for a high conversion of the 

cellulose and hemicellulose to simple 

sugars, minimize the degradation of 

these sugars to undesired forms that 

reduce fuel yields and inhibit 

fermentation, not require especially 

large or expensive reaction vessels, and 

be a relatively robust and simple 

process. No single biomass pretreatment 

method has yet been discovered that 

meets all of these goals, but rather a 

variety of options are being used by 

various cellulosic fuel producers, each 

with their own strengths and 

weaknesses. Dilute acid pretreatment 

and alkaline pretreatment are two 

methods currently being used that 

attack the hemicellulose and lignin 

portions of the cellulosic biomass 

respectively. Other methods, such as 

steam explosion and ammonia fiber 

expansion, seek to use high temperature 

and pressure, followed by rapid 

decompression to disrupt the structure 

of the cellulosic biomass and allow for 

a more efficient hydrolysis of the 

cellulose and hemicellulose to simple 

sugars. Each of these methods is 

discussed in more detail in a technical 

memo that has been added to the 

docket.20 The cost and characteristics of 

the cellulosic feedstock being processed 

is likely to have a significant impact on 

the pretreatment process that is used. 

c. Hydrolysis 

In the hydrolysis step the cellulose 

and any remaining hemicellulose are 

converted to simple sugars. There are 

two main methods of hydrolysis: acid 

hydrolysis and enzymatic hydrolysis. 

Acid hydrolysis is the oldest technology 

for the conversion of cellulosic 

feedstock to ethanol and can only be 

used following an acid pretreatment 

process. An alternative method is to use 

a combination of enzymes to perform 

the hydrolysis after the biomass has 

been pretreated. This process is 

potentially more effective at 

hydrolyzing pretreated biomass but in 

the past has not been economically 

feasible due to the prohibitively high 

cost of the enzymes. The falling cost of 

these enzymes in recent years has made 

the production of cellulosic biofuels 

using enzymatic hydrolysis possible. 

The lignin is largely unaffected by the 

hydrolysis and fuel production steps but 

is carried through these processes until 

it is separated out in the fuel separation 

step and burned for process energy or 

sold as a co-product. 

i. Acid Hydrolysis 

Acid hydrolysis is a technique that 

has been used for over 100 years to 

convert cellulosic feedstocks into fuels. 

In the acid hydrolysis process the lignin 

and cellulose portions of the feedstock 

that remain after the hemicellulose has 

been dissolved, hydrolyzed, and 

separated during the dilute acid 

pretreatment process is treated with a 

second acid stream. This second acid 

treatment uses a less concentrated acid 

than the pretreatment stage but at a 

higher temperature, as high as 215 °C. 

This treatment hydrolyzes the cellulose 

into glucose and other six-carbon sugars 

that are then fed to biological organisms 

to produce the desired fuel. It is 

necessary to hydrolyze the 

hemicellulose and cellulose in two 

separate steps to prevent the conversion 

of the pentose sugars that result from 

the hydrolysis of the hemicellulose from 

being further converted into furfural and 

other chemicals. This would not only 

reduce the total production of sugars 

from the cellulosic feedstock, but also 

inhibit the production of fuel from the 

sugars in later stages of the process. 

The acidic solution containing the 

sugars produced as a result of the 

hydrolysis reaction must also be treated 

so that this stream can be fed to the 

biological organisms that will convert 

these sugars into fuel. In order to 

operate an acid hydrolysis process cost 

effectively the acid must be recovered, 

not simply neutralized. Methods 

currently being used to recover this acid 

include membrane separation and 

continuous ion exchange. The 

advantages of using an acid hydrolysis 

are that this process is well understood 


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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 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 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 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 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. 

The distillation of ethanol is a very 

energy intensive process and new 

technologies, such as membrane 

separation, are being developed that 


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21US. DOE. Technologies: Processing and 

Conversion. Accessed at: http:// 

www1.eere.energy.gov/biomass/processing

_conversion.html on October 28, 2008. 22EERE, 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. 

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 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 

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. 

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 increase 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 costcompetitive 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 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, nonfermentable material left over from highstarch 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 


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76812 Federal Register / Vol. 75, No. 236 / Thursday, December 9, 2010 / Rules and Regulations 

23Aden, Andy, Mixed Alcohols from Woody 

Biomass—2010, 2015, 2022, National Renewable 

Energy Laboratory (NREL), September 23, 2009. 

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 mixed-alcohols route, 

refer to NREL technical 

documentation.23

BILLING CODE 6560–50–P 


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Federal Register / Vol. 75, No. 236 / Thursday, December 9, 2010 / Rules and Regulations 76813 

Figure IV.C.2–2 is a block diagram of 

a biomass to liquids (BTL) process 

which produces diesel fuel and naphtha 

through a thermochemical process. 


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76814 Federal Register / Vol. 75, No. 236 / Thursday, December 9, 2010 / Rules and Regulations 

24Lin 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. 

25S. 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. 

BILLING CODE 6560–50–C 

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. 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 super-heaters generate steam that 

drives turbines on compressors and 

electrical generators. The heat balance 

around a thermochemical unit or 

thermochemical combined unit must be 

carefully designed and tuned in order to 

avoid unnecessary heat losses.25 These 

facilities greatly increase the thermal 

efficiency of these plants, but they add 

to the very high capital costs of these 

technologies. 

a. Ethanol Based on a Thermochemical 

Platform 

Conceptual designs and technoeconomic models have been developed 

for ethanol production via mixed 

alcohol synthesis using catalytic 

processes. The proposed mixed alcohol 

process produces a mixture of ethanol 

along with higher normal alcohols (e.g., 

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

The by-product higher normal alcohols 

have value as commodity chemicals and 

fuel additives. 

The liquid 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 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 Canadianbased company was recently announced 

as a recipient of a $50 million grant 

from DOE to build a woody biomass-toethanol 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 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 


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technology for producing diesel fuel and 

naphtha. The principal aspect of 

Choren’s process is their patented threestage 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 U.S. 

Choren is also planning to build a 

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

their Freiberg/Saxony plant is 

operational in Germany. 

Baard Energy is a U.S. company 

which plans on utilizing a 

thermochemical technology for 

producing diesel fuel and naphtha. 

Baard, however, plans on primarily 

combusting coal and cofiring biomass 

with the coal. Cofiring the biomass with 

the coal will make their first plant more 

like the coal-to-liquids plants which are 

operating today, which may help to 

convince investors that this technology 

is already tested. Baard’s coal and 

biomass-to-liquids plant is not expected 

to be operational until at least 2012. 

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 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 

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 process replaces the catalyst 

needed in a typical thermochemical 

process. These microorganisms allow 

for a higher variation of the incoming 

syngas stream properties, avoid the 

necessity of a water-shift reaction 

preceding traditional catalytic 

conversion, and are able to operate at 

lower temperatures and pressures than 

those required for a catalytic conversion 

to ethanol. Microorganisms, unlike a 

catalyst, are also self-sustaining and do 

not require periodic replacement. They 

are; however, susceptible to bacterial 

and viral infections which requires 

periodic cleaning of the fermentation 

reactors. 

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 ligninbased 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 


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26 DOE EERE Biomass Program. ‘‘Thermochemical 

Conversion Processes: Pyrolysis’’ http:// 

www1.eere.energy.gov/biomass/ 

thermochemical_processes.html, November 6, 2008. 

feedstock to acetic acid. This reaction 

creates no carbon dioxide, unlike 

traditional fermentation using yeast, 

preserving the maximum amount of 

carbon for the finished fuel. The acetic 

acid stream then undergoes 

esterification to create ethyl acetate. 

Meanwhile, the syngas stream from the 

gasification of lignin and other residue 

is separated into its carbon monoxide 

and hydrogen components. The carbon 

monoxide stream can be further 

combusted to provide process heat or 

energy. The hydrogen stream is 

combined with the ethyl acetate in a 

hydrolysis reaction to form ethanol. 

Acetic acid and ethyl acetate also form 

the precursors to many other chemical 

compounds and therefore may 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 

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 bio-fuels 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. 

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 

25% water which is intimately mixed 

and does not easily separate into 

another phase with time. Since the biooil 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 biomethanol 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 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 


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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 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 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, 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. 

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. 

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 


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27 75 FR 59622, September 28, 2010. 

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. 

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 RINgenerating pathways, and only for 

volumes of fuel produced between July 

1, 2010 and the effective date of a new 

RIN-generating 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 § 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 RIN-generating 

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 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 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: 


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28 75 FR 42238, 42262, July 20, 2010. 

(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 

RIN-generating 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 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. 

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 

§ 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 RINgenerating 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 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 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 


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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. 

• 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 nondomestically 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 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. 

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, 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-by-crop basis. This 

approach will simplify the regulations, 

as it permits EPA to specify the data, 


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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. 

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 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-bycase 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. 

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. 

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 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 


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76822 Federal Register / Vol. 75, No. 236 / Thursday, December 9, 2010 / Rules and Regulations 

29The 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. 

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 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 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 farm-level land use 

data that includes all cropland and 

pastureland in the U.S. EPA also 

considered USDA Census of Agriculture 

data, which consists of a full census of 

the U.S. agricultural sector once every 

five years, as well as the USDA National 

Agricultural Statistics Service (NASS) 

Crop Data Layer (CDL), which is based 

on satellite data. 

In establishing the total amount of 

existing agricultural land for the U.S. 

aggregate compliance approach 

determination, EPA relied on the RFS2 

definitions of the relevant terms, 

including planted crops, crop residue, 

and agricultural land, which is defined 

as consisting of cropland, pastureland 

and 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 

country, and whether EPA should be 

able to make such a determination in 

the context of a petition for application 

of the aggregate approach to a foreign 

country. 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. 

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 


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Federal Register / Vol. 75, No. 236 / Thursday, December 9, 2010 / Rules and Regulations 76823 

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 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 

• 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 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 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 

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 


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76824 Federal Register / Vol. 75, No. 236 / Thursday, December 9, 2010 / Rules and Regulations 

30More 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. 

31See U.S. Department of Labor, Bureau of Labor 

Statistics (BLS), Consumer Price Index Web site at: 

http://www.bls.gov/cpi/. 

(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 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. 

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. 

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 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 parties for end-ofyear compliance should they need them 

at a price of $1.13 per gallon-RIN. To 

calculate this price, EPA first 

determined the average wholesale 


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Federal Register / Vol. 75, No. 236 / Thursday, December 9, 2010 / Rules and Regulations 76825 

32See 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. 

34See 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. 

(refinery gate) price of gasoline using 

the most recent 12 months of data 

available from the EIA Web site 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 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. 

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. 

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 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 


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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. 

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 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. 

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. 

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 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 foreigngrown 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 

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. 

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 


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include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of today’s rule on small entities, small 

entity is defined as: (1) A small business 

as defined by the Small Business 

Administration’s (SBA) regulations at 13 

CFR 121.201; (2) a small governmental 

jurisdiction that is a government of a 

city, county, town, school district or 

special district with a population of less 

than 50,000; and (3) a small 

organization that is any not-for-profit 

enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of today’s 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 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 

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 

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 and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law 

104–113, 12(d) (15 U.S.C. 272 note) 

directs EPA to use voluntary consensus 

standards in its regulatory activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impractical. Voluntary consensus 

standards are technical standards (e.g., 

materials specifications, test methods, 

sampling procedures, and business 

practices) that are developed or adopted 

by voluntary consensus standards 

bodies. NTTAA directs EPA to provide 

Congress, through OMB, explanations 

when the Agency decides not to use 

available and applicable voluntary 

consensus standards. 

This action does not involve technical 

standards. Therefore, EPA 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 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. 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: November 24, 2010. 

Lisa P. Jackson, 

Administrator. 

■ For the reasons set forth in the 

preamble, 40 CFR part 80 is amended as 

follows: 

PART 80—REGULATION OF FUELS 

AND FUEL ADDITIVES 

■ 1. The authority citation for part 80 

continues to read as follows: 

Authority: 42 U.S.C. 7414, 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. 

* * * * * 

■ 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. 

(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 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. 

(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 gallonRINs 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. 

(iii) Retired RINs must have a K code 

of 2. 

(iv) Retired RINs must have been 

generated in the same year as the gallonRINs 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 gallonRINs 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 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 


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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. 

(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. 

(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 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 RINgenerating 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: 

§ 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 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 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 


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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. 

(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. 

(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. 

(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). 

[FR Doc. 2010–30296 Filed 12–8–10; 8:45 am] 

BILLING CODE 6560–50–P 


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