
[Federal Register: July 20, 2010 (Volume 75, Number 138)]
[Proposed Rules]               
[Page 42237-42268]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr20jy10-30]                         


[[Page 42237]]

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Part III





Environmental Protection Agency





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40 CFR Part 80



Regulation of Fuels and Fuel Additives: 2011 Renewable Fuel Standards; 
Proposed Rule


[[Page 42238]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 80

[EPA-HQ-OAR-2010-0133; FRL-9175-8]
RIN 2060-AQ16

 
Regulation of Fuels and Fuel Additives: 2011 Renewable Fuel 
Standards

AGENCY: Environmental Protection Agency (EPA).

ACTION: Notice of proposed rulemaking.

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SUMMARY: Under the Clean Air Act Section 211(o), as amended by the 
Energy Independence and Security Act of 2007 (EISA), the Environmental 
Protection Agency is required to set the renewable fuel standards each 
November for the following year based on gasoline and diesel 
projections from EIA. Additionally, EPA is required to set the 
cellulosic biofuel standard each year based on the volume projected to 
be available during the following year, using EIA projections and 
assessments of production capability from industry. This regulatory 
action proposes these annual standards for cellulosic biofuel, biomass-
based diesel, advanced biofuel, and renewable fuels that apply to all 
gasoline and diesel produced or imported in year 2011. This action also 
presents two proposed changes to the RFS2 regulations. The first would 
create a temporary and limited means for certain renewable fuel 
producers to generate delayed RINs after they have produced and sold 
renewable fuel. This proposed provision would apply only to those 
producers who use canola oil, grain sorghum, pulpwood, or palm oil to 
produce renewable fuel. The second proposed regulatory provision would 
establish criteria for foreign countries to adopt an aggregate approach 
to compliance with the renewable biomass provision akin to that 
applicable to the U.S.

DATES: Comments must be received on or before August 19, 2010.
    Hearing: We do not expect to hold a public hearing. However, if we 
receive such a request we will publish information related to the 
timing and location of the hearing and the timing of a new deadline for 
public comments.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2010-0133, by one of the following methods:
     http://www.regulations.gov: Follow the online instructions 
for submitting comments.
     E-mail: asdinfo@epa.gov.
     Mail: Air and Radiation Docket and Information Center, 
Environmental Protection Agency, Mailcode: 2822T, 1200 Pennsylvania 
Ave., NW., Washington, DC 20460.
     Hand Delivery: EPA Docket Center, EPA West Building, Room 
3334, 1301 Constitution Ave., NW., Washington, DC 20460. Such 
deliveries are only accepted during the Docket's normal hours of 
operation, and special arrangements should be made for deliveries of 
boxed information.
    Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2010-0133. EPA's policy is that all comments received will be included 
in the public docket without change and may be made available online at 
http://www.regulations.gov, including any personal information 
provided, unless the comment includes information claimed to be 
Confidential Business Information (CBI) or other information whose 
disclosure is restricted by statute. Do not submit information that you 
consider to be CBI or otherwise protected through http://
www.regulations.gov or e-mail. The http://www.regulations.gov Web site 
is an ``anonymous access'' system, which means EPA will not know your 
identity or contact information unless you provide it in the body of 
your comment. If you send an e-mail comment directly to EPA without 
going through http://www.regulations.gov your e-mail address will be 
automatically captured and included as part of the comment that is 
placed in the public docket and made available on the Internet. If you 
submit an electronic comment, EPA recommends that you include your name 
and other contact information in the body of your comment and with any 
disk or CD-ROM you submit. If EPA cannot read your comment due to 
technical difficulties and cannot contact you for clarification, EPA 
may not be able to consider your comment. Electronic files should avoid 
the use of special characters, any form of encryption, and be free of 
any defects or viruses. For additional information about EPA's public 
docket visit the EPA Docket Center homepage at http://www.epa.gov/
epahome/dockets.htm. For additional instructions on submitting 
comments, go to Section I.B of the SUPPLEMENTARY INFORMATION section of 
this document.
    Docket: All documents in the docket are listed in the http://
www.regulations.gov index. Although listed in the index, some 
information is not publicly available, e.g., CBI or other information 
whose disclosure is restricted by statute. Certain other material, such 
as copyrighted material, will be publicly available only in hard copy. 
Publicly available docket materials are available either electronically 
in http://www.regulations.gov or in hard copy at the Air and Radiation 
Docket and Information Center, EPA/DC, EPA West, Room 3334, 1301 
Constitution Ave., NW., Washington, DC. The Public Reading Room is open 
from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal 
holidays. The telephone number for the Public Reading Room is (202) 
566-1744, and the telephone number for the Air Docket is (202) 566-
1742.

FOR FURTHER INFORMATION CONTACT: Julia MacAllister, Office of 
Transportation and Air Quality, Assessment and Standards Division, 
Environmental Protection Agency, 2000 Traverwood Drive, Ann Arbor, MI 
48105; Telephone number: 734-214-4131; Fax number: 734-214-4816; E-mail 
address: macallister.julia@epa.gov, or Assessment and Standards 
Division Hotline; telephone number 734-214-4636; E-mail address 
asdinfo@epa.gov.

SUPPLEMENTARY INFORMATION: 

I. General Information

A. Does this action apply to me?

    Entities potentially affected by this proposed rule are those 
involved with the production, distribution, and sale of transportation 
fuels, including gasoline and diesel fuel or renewable fuels such as 
ethanol and biodiesel. Potentially regulated categories include:

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                                            NAICS \1\                       Examples of potentially regulated
                Category                      codes       SIC \2\ codes                  entities
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Industry...............................          324110            2911  Petroleum Refineries.
Industry...............................          325193            2869  Ethyl alcohol manufacturing.
Industry...............................          325199            2869  Other basic organic chemical
                                                                          manufacturing.
Industry...............................          424690            5169  Chemical and allied products merchant
                                                                          wholesalers.
Industry...............................          424710            5171  Petroleum bulk stations and terminals.
Industry...............................          424720            5172  Petroleum and petroleum products
                                                                          merchant wholesalers.

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Industry...............................          454319            5989  Other fuel dealers.
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\1\ North American Industry Classification System (NAICS).
\2\ Standard Industrial Classification (SIC) system code.

    This table is not intended to be exhaustive, but rather provides a 
guide for readers regarding entities likely to be regulated by this 
proposed action. This table lists the types of entities that EPA is now 
aware could potentially be regulated by this proposed action. Other 
types of entities not listed in the table could also be regulated. To 
determine whether your activities would be regulated by this proposed 
action, you should carefully examine the applicability criteria in 40 
CFR part 80. If you have any questions regarding the applicability of 
this proposed action to a particular entity, consult the person listed 
in the preceding section.

B. What should I consider as I prepare my comments for EPA?

1. Submitting CBI
    Do not submit this information to EPA through http://
www.regulations.gov or e-mail. Clearly mark the part or all of the 
information that you claim to be CBI. For CBI information in a disk or 
CD-ROM that you mail to EPA, mark the outside of the disk or CD-ROM as 
CBI and then identify electronically within the disk or CD-ROM the 
specific information that is claimed as CBI. In addition to one 
complete version of the comment that includes information claimed as 
CBI, a copy of the comment that does not contain the information 
claimed as CBI must be submitted for inclusion in the public docket. 
Information so marked will not be disclosed except in accordance with 
procedures set forth in 40 CFR part 2.
2. Tips for Preparing Your Comments
    When submitting comments, remember to:
     Identify the rulemaking by docket number and other 
identifying information (subject heading, Federal Register date and 
page number).
     Follow directions--The agency may ask you to respond to 
specific questions or organize comments by referencing a Code of 
Federal Regulations (CFR) part or section number.
     Explain why you agree or disagree, suggest alternatives, 
and substitute language for your requested changes.
     Describe any assumptions and provide any technical 
information and/or data that you used.
     If you estimate potential costs or burdens, explain how 
you arrived at your estimate in sufficient detail to allow for it to be 
reproduced.
     Provide specific examples to illustrate your concerns, and 
suggest alternatives.
     Explain your views as clearly as possible, avoiding the 
use of profanity or personal threats.
     Make sure to submit your comments by the comment period 
deadline identified.

Outline of This Preamble

I. Executive Summary
    A. Statutory Requirements for Cellulosic Biofuel
    B. Assessment of 2011 Cellulosic Biofuel Volume
    C. Advanced Biofuel and Total Renewable Fuel
    D. Proposed Percentage Standards
II. Volume Production and Import Potential for 2011
    A. Cellulosic Biofuel
    1. Domestic Cellulosic Ethanol
    2. Domestic Cellulosic Diesel
    3. Other Domestic Cellulosic Biofuels
    4. Imports of Cellulosic Biofuel
    5. Summary of Volume Projections
    B. Potential Limitations
    C. Advanced Biofuel and Total Renewable Fuel
    D. Biomass-Based Diesel
III. Proposed Percentage Standards for 2011
    A. Background
    B. Calculation of Standards
    1. How are the standards calculated?
    2. Small Refineries and Small Refiners
IV. Cellulosic Biofuel Technology Assessment
    A. What pathways are valid for the production of cellulosic 
biofuel?
    B. Cellulosic Feedstocks
    C. Emerging Technologies
    1. Biochemical
    a. Feedstock Handling
    b. Biomass Pretreatment
    c. Hydrolysis
    i. Acid Hydrolysis
    ii. Enzymatic Hydrolysis
    d. Fuel Production
    e. Fuel Separation
    f. Process Variations
    g. Current Status of Biochemical Conversion Technology
    h. Major Hurdles to Commercialization
    2. Thermochemical
    a. Ethanol Based on a Thermochemical Platform
    b. Diesel and Naphtha Production Based on a Thermochemical 
Platform
    3. Hybrid Thermochemical/Biochemical Processes
    4. Pyrolysis and Depolymerization
    a. Pyrolysis Diesel Fuel and Gasoline
    b. Catalytic Depolymerization
    5. Catalytic Reforming of Sugars to Gasoline
V. Proposed Changes to RFS2 Regulations
    A. Delayed RIN Generation for New Pathways
    B. Criteria and Process for Adoption of Aggregate Approach to 
Renewable Biomass for Foreign Countries
    1. Criterion and Considerations
    2. Data Sources
    3. Petition Submission
    4. Petition Process
VI. Public Participation
    A. How do I submit comments?
    B. How should I submit CBI to the agency?
VII. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer Advancement Act
    J. Executive Order 12898: Federal Actions to Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
VIII. Statutory Authority

I. Executive Summary

    The Renewable Fuel Standard (RFS) program began in 2007 following 
the requirements in Clean Air Act (CAA) section 211(o) which were 
implemented through the Energy Policy Act of 2005 (EPAct). The 
statutory requirements for the RFS program were subsequently modified 
through the Energy Independence and Security Act of 2007 (EISA), 
resulting in the release of revised regulatory requirements on March 
26, 2010 \1\. In general, the transition from the RFS1 requirements of 
EPAct to the RFS2 requirements of EISA will occur on July 1, 2010.
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    \1\ 75 FR 14670.
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    EPA is required to determine and publish the applicable annual 
percentage standards for each compliance year by November 30 of the 
previous year. The determination of the applicable standards under RFS2 
requires the EPA to conduct an in-depth evaluation of the volume of 
qualifying cellulosic biofuel that can be supplied in the following 
year. If the projected

[[Page 42240]]

volume of cellulosic biofuel production is less than the required 
volume specified in the statute, EPA must lower the required volume 
used to set the annual cellulosic biofuel percentage standard to the 
projected volume of production. We must also determine whether the 
advanced biofuel and/or total renewable fuel volumes should be reduced 
by the same or a lesser amount. Since these evaluations will be based 
on evolving information about emerging segments of the biofuels 
industry, and may result in the required volumes differing from those 
in the statute, we believe that a notice-and-comment rulemaking process 
is appropriate. Today's notice provides our evaluation of the projected 
production of cellulosic biofuel for 2011, and proposed percentage 
standards for compliance year 2011. We will complete our evaluation 
based on comments received in response to this proposal, the Production 
Outlook Reports due to the Agency on September 1, 2010, the estimate of 
projected biofuel volumes that the EIA is required to provide to EPA by 
October 31, and other information that becomes available, and will 
finalize the standards for 2011 by November 30, 2010.
    Today's proposed rule does not include an assessment of the 
environmental impacts of the standards we are proposing for 2011. All 
of the impacts of the RFS2 program were addressed in the RFS2 final 
rule published on March 26, 2010, including impacts of the biofuel 
standards specified in the statute. Today's rulemaking simply proposes 
the standards for 2011 whose impacts were already analyzed previously.
    Today's notice also presents two proposed changes to the RFS2 
regulations. The first would create a temporary and limited means for 
certain renewable fuel producers to generate RINs after they have 
produced and sold renewable fuel. This proposed provision for ``Delayed 
RINs'' would apply only to those producers who use canola oil, grain 
sorghum, pulpwood, or palm oil to produce renewable fuel, and only if 
EPA determines that fuel pathways utilizing these feedstocks provide 
appropriate greenhouse gas reductions as compared to baseline fuels to 
enable EPA to list the pathways in Table 1 to Sec.  80.1426. We are 
proposing that the provision for Delayed RINs would apply only to these 
four feedstocks because we would have included them in the final RFS2 
rule if the lifecycle analyses had been completed in time. The 
greenhouse gas (GHG) lifecycle impacts of these four feedstocks are 
currently being analyzed as a supplement to the RFS2 final rule and are 
expected to be completed in 2010. The second proposed regulatory 
provision would establish criteria for EPA to use in determining 
whether to authorize renewable fuel producers using foreign-grown 
feedstocks to use an aggregate approach to compliance with the 
renewable biomass verification provisions, akin to that applicable to 
producers using crops and crop residue grown in the United States. 
Further discussion of both of these proposed provisions can be found in 
Section V.
    Finally, we note that in the RFS2 final rule we also stated our 
intent to make two announcements each year:
     Set the price for cellulosic biofuel waiver credits that 
will be made available to obligated parties in the event that we reduce 
the volume of cellulosic biofuel below the volume required by EISA.
     Announce the results of our assessment of the aggregate 
compliance approach for verifying renewable biomass requirements for 
U.S. crops and crop residue, and our conclusion regarding whether the 
aggregate compliance provision will continue to apply.
    For both of these determinations EPA will use specific sources of 
data and a methodology laid out in the RFS2 final rule. We intend to 
present the results of both of these determinations in the final rule 
following today's proposal.

A. Statutory Requirements for Cellulosic Biofuel

    The volumes of renewable fuel that must be used under the RFS2 
program each year (absent an adjustment or waiver by EPA) are specified 
in CAA 211(o)(2). These volumes for 2011 are shown in Table I.A-1.

       Table I.A-1--Required Volumes in the Clean Air Act for 2011
                               [Bill gal]
------------------------------------------------------------------------
                                                               Ethanol
                                                 Actual      equivalent
                                                 volume        volume
------------------------------------------------------------------------
Cellulosic biofuel..........................          0.25      \a\ 0.25
Biomass-based diesel........................          0.80          1.20
Advanced biofuel............................          1.35          1.35
Renewable fuel..............................         13.95         13.95
------------------------------------------------------------------------
\a\ This value assumes that all cellulosic biofuel would be ethanol. If
  any portion of the renewable fuel used to meet the cellulosic biofuel
  volume mandate has a volumetric energy content greater than that for
  ethanol, this value will be higher.

    By November 30 of each year, the EPA is required under CAA 211(o) 
to determine and publish in the Federal Register the renewable fuel 
standards for the following year. These standards are to be based in 
part on transportation fuel volumes estimated by the Energy Information 
Administration (EIA) for the following year. The calculation of the 
percentage standards is based on the formulas in Sec.  80.1405(c) which 
express the required volumes of renewable fuel as a volume percentage 
of gasoline and diesel sold or introduced into commerce in the 48 
contiguous states plus Hawaii.
    The statute requires the EPA to determine whether the projected 
volume of cellulosic biofuel production for the following year is less 
than the minimum applicable volume shown in Table I.A-1. If this is the 
case, then the standard for cellulosic biofuel must be based upon the 
volume projected to be available rather than the applicable volume in 
the statute. In addition, if EPA reduces the required volume of 
cellulosic biofuel below the level specified in the statute, the Act 
also indicates that we may reduce the applicable volume of advanced 
biofuels and total renewable fuel by the same or a lesser volume.
    As described in the final rule for the RFS2 program, we intend to 
examine EIA's projected volumes and other available data including the 
Production Outlook Reports required under Sec.  80.1449 in making the 
determination of the appropriate volumes to require for 2011. Since the 
first set of Production Outlook Reports are not due until September 1, 
2010, they were not available for today's proposal but will be 
considered for development of the

[[Page 42241]]

final rule to be released by November 30, 2010.

B. Assessment of 2011 Cellulosic Biofuel Volume

    To estimate the volume of cellulosic biofuel that could be made 
available in the U.S. in 2011, we researched all potential production 
sources by company and facility. This included sources that were still 
in the planning stages, those that were under construction, and those 
that are already producing some volume of cellulosic ethanol, 
cellulosic diesel, or some other type of cellulosic biofuel. We 
considered all pilot and demonstration plants as well as commercial 
plants. From this universe of potential cellulosic biofuel sources we 
identified the subset that had a possibility of producing some volume 
of qualifying cellulosic biofuel for use as transportation fuel in 
2011. We then conducted a rigorous process of contacting all of these 
producers to determine which ones were actually in a position to 
produce and make available any commercial volumes of cellulosic biofuel 
in 2011. Based on information gathered in this process, we estimated 
the maximum potentially available 2011 volumes. For the final rule, we 
will specify the projected available volume for 2011 that will be the 
basis for the percentage standard for cellulosic biofuel. To determine 
the projected available volume, we will consider factors such as the 
current and expected state of funding, the status of the technology and 
contracts for feedstocks, and progress towards construction and 
production goals. A complete list of all the factors we expect to 
consider in this process is provided in Section II.A.5.
    In our assessment we evaluated both domestic and foreign sources of 
cellulosic biofuel. Of the domestic sources, we estimated that seven 
facilities have the potential to make volumes of cellulosic biofuel 
available for transportation use in the U.S. in 2011. We also 
determined that one facility in Canada has the potential to export some 
cellulosic biofuel to the U.S. These facilities are listed in Table 
I.B-1 along with our estimate of the maximum potentially available 
volume.

              Table I.B-1--Maximum Potentially Available Cellulosic Biofuel Plant Volumes for 2011
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                                                                                           Maximum potentially
                                                                                             available volume
               Company                         Location                Fuel type            (million ethanol-
                                                                                           equivalent gallons)
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AE Advanced Fuels Keyes..............  Keyes, CA..............  Ethanol................                     0.5
Agresti Biofuels.....................  Pike County, KY........  Ethanol................                     1
Bell Bio-Energy......................  Atlanta, GA............  Diesel feedstock.......                    11.9
Cello Energy.........................  Bay Minette, AL........  Diesel.................                     8.5
DuPont Dansico.......................  Vonore, TN.............  Ethanol................                     0.15
Fiberight............................  Blairstown, IA.........  Ethanol................                     2.8
Iogen Corporation....................  Ottawa, Ont............  Ethanol................                     0.25
KL Energy Corp/WBE...................  Upton, WY..............  Ethanol................                     0.4
                                                                                        ------------------------
    Total............................  .......................  .......................                    25.5
----------------------------------------------------------------------------------------------------------------

    The volumes in Table I.B-1 for each facility represent the volume 
that would be produced in 2011 based upon the owner's expected month of 
startup and an assumed period of production rampup for testing and 
process validation. However, none of the facilities we evaluated are 
currently producing cellulosic biofuel at the rates they project for 
2011. Moreover, there are other uncertainties associated with each 
facility's projected volume that could result in less production volume 
in 2011 than the maximum potentially available values shown in Table 
I.B-1. These uncertainties include outstanding issues in areas such as 
technology, funding, and construction. Historical successes in meeting 
various past milestones also play a role in assessing the likelihood of 
meeting future milestones. A detailed discussion of these uncertainties 
is presented in Section II.A. Finally, the volumes that should be 
considered for setting the 2011 standard are those that result from 
valid cellulosic biofuel pathways in Table 1 to Sec.  80.1426. As 
described more fully in Section IV.A, some of the facilities in Table 
I.B-1 may use feedstocks that have not yet been subjected to lifecycle 
analyses to determine if the pathway meets the applicable GHG 
thresholds.
    Based on our preliminary assessment for this NPRM, we believe that 
we could justify a 2011 cellulosic biofuel volume requirement of at 
least 6.5 million ethanol-equivalent gallons, and potentially as high 
as 25.5 million gallons. For the final rule we will use additional 
information that becomes available after publication of this proposal 
and a more precise assessment of the uncertainties associated with each 
facility to determine the projected available volume on which to base 
the cellulosic biofuel percentage standard for 2011.

C. Advanced Biofuel and Total Renewable Fuel

    As described in Section I.A above, the statute indicates that we 
may reduce the applicable volume of advanced biofuel and total 
renewable fuel if we determine that the projected volume of cellulosic 
biofuel production for 2011 falls short of the statutory volume of 250 
million gallons. As shown in Table I.B-1, we are proposing a 
determination that this is the case. Therefore, we also needed to 
evaluate the need to lower the required volumes for advanced biofuel 
and total renewable fuel.
    We first considered whether it appears likely that the required 
biomass-based diesel volume of 0.8 billion gallons can be met with 
existing biodiesel production capacity in 2011. As discussed in Section 
II.D, we believe that the 0.8 billion gallon standard can indeed be 
met. Since biodiesel has an Equivalence Value of 1.5, 0.8 billion 
physical gallons of biodiesel would provide 1.20 billion ethanol-
equivalent gallons that can be counted towards the advanced biofuel 
standard of 1.35 billion gallons. Of the remaining 0.15 bill gallons, 
up to 0.026 bill gallons would be met with the proposed volume of 
cellulosic biofuel. Based on our analysis as described in Section II.C, 
there may be sufficient volumes of other advanced biofuels, such as 
imported sugarcane ethanol, additional biodiesel, or renewable diesel, 
such that the standard for advanced biofuel could remain at the 
statutory level of 1.35 billion gallons. However, uncertainty in

[[Page 42242]]

the potential volumes of these other advanced biofuels coupled with the 
range of potential production volumes of cellulosic biofuel could 
provide a rationale for lowering the advanced biofuel standard. If we 
do not simultaneously lower the required volume for total renewable 
fuel, the result would be that additional volumes of conventional 
renewable fuel, such as corn-starch ethanol, would be produced, 
effectively replacing some advanced biofuels. In today's NPRM we are 
proposing that neither the required 2011 volumes for advanced biofuel 
nor total renewable fuel be lowered below the statutory volumes. 
However, we request comment on whether the advanced biofuel and/or 
total renewable fuel volume requirements should be lowered if, as we 
propose, EPA lowers the required cellulosic biofuel volume from that 
specified in the Act.

D. Proposed Percentage Standards

    The renewable fuel standards are expressed as a volume percentage, 
and are used by each refiner, blender or importer to determine their 
renewable fuel volume obligations. The applicable percentages are set 
so that if each regulated party meets the percentages, and if EIA 
projections of gasoline and diesel use are accurate, then the amount of 
renewable fuel, cellulosic biofuel, biomass-based diesel, and advanced 
biofuel used will meet the volumes required on a nationwide basis. To 
calculate the percentage standard for cellulosic biofuel for 2011, we 
have used a potential volume range of 6.5-25.5 million ethanol-
equivalent gallons (representing 5-17.1 million physical gallons). For 
the final rule, EPA intends to pick a single value from within this 
range to represent the projected available volume on which the 2011 
percentage standard for cellulosic biofuel will be based. We are also 
proposing that the applicable volumes for biomass-based diesel, 
advanced biofuel, and total renewable fuel for 2011 will be those 
specified in the statute. These volumes are shown in Table I.D-1.

                                     Table I.D-1--Proposed Volumes for 2011
----------------------------------------------------------------------------------------------------------------
                                                   Actual volume                Ethanol equivalent volume
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel.......................  5-17.1 mill gal.............  6.5-25.5 mill gal.
Biomass-based diesel.....................  0.80 bill gal...............  1.20 bill gal.
Advanced biofuel.........................  1.35 bill gal...............  1.35 bill gal.
Renewable fuel...........................  13.95 bill gal..............  13.95 bill gal.
----------------------------------------------------------------------------------------------------------------

    Four separate standards are required under the RFS2 program, 
corresponding to the four separate volume requirements shown in Table 
I.D-1. The specific formulas we use to calculate the renewable fuel 
percentage standards are contained in the regulations at Sec.  80.1405 
and repeated in Section III.B.1. The percentage standards represent the 
ratio of renewable fuel volume to non-renewable gasoline and diesel 
volume. The projected volumes of gasoline and renewable fuels used to 
calculate the standards are provided by EIA's Short-Term Energy Outlook 
(STEO) \2\. The projected volume of transportation diesel used to 
calculate the standards is provided by EIA's 2010 Annual Energy Outlook 
(early release version).\3\ Because small refiners and small refineries 
are also regulated parties beginning in 2011 \4\, there is no small 
refiner/refinery volume adjustment to the 2011 standard as there was 
for the 2010 standard. Thus, the increase in the percentage standards 
relative to 2010 appears smaller than would otherwise be the case, 
since more obligated parties will be participating in the program. The 
proposed standards for 2011 are shown in Table I.D-2. Detailed 
calculations can be found in Section III.
---------------------------------------------------------------------------

    \2\ The March 2010 issue of STEO was used for today's proposal. 
We intend to use the October 2010 version for the final rule.
    \3\ EIA has recommended the use of the Annual Energy Outlook 
(AEO) rather than the Short Term Energy Outlook as a better 
representation of the estimated transportation sector diesel fuel 
use. We will use the most recent version of AEO in the final values 
of the standards.
    \4\ The Department of Energy concluded that there is no reason 
to believe that any small refinery would be disproportionately 
harmed by inclusion in the proposed RFS2 program for 2011 and 
beyond. See DOE report ``EPACT 2005 Section 1501 Small Refineries 
Exemption Study'', (January 2009). We will revisit extensions to the 
exemption for small refiners and refineries if DOE revises their 
study and provides a different conclusion, or an individual small 
refinery is able to demonstrate that it will suffer a 
disproportionate economic hardship under the RFS program.

           Table I.D-2--Proposed Percentage Standards for 2011
------------------------------------------------------------------------
                                                              Percent
------------------------------------------------------------------------
Cellulosic biofuel......................................     0.004-0.015
Biomass-based diesel....................................            0.68
Advanced biofuel........................................            0.77
Renewable fuel..........................................            7.95
------------------------------------------------------------------------

II. Volume Production and Import Potential for 2011

    In order to project production volumes of cellulosic biofuel in 
2011 for use in setting the percentage standards, we collected 
information on individual facilities that have the potential to produce 
qualifying volumes for consumption as transportation fuel, heating oil, 
or jet fuel in the U.S. in 2011. This section describes the potential 
volumes that we believe could be produced or imported in 2011 as well 
as the uncertainties associated with those volumes. The volumes listed 
in this section do not represent the projected available volume of 
cellulosic biofuel that will be used to finalize the cellulosic biofuel 
percentage standard for 2011. Rather, for today's NPRM we have assessed 
the maximum potentially available volume for 2011, which is intended to 
represent an upper bound of the volume of fuel that may be produced and 
made available. The production of cellulosic biofuel remains highly 
uncertain, and EPA expects that the volume of cellulosic biofuel used 
to set the 2011 percentage standard will be a lesser volume than this 
maximum potentially available volume. Section III describes the 
conversion of our maximum potentially available volumes for cellulosic 
biofuel into a range of percentage standards.
    While the 2011 volume projections in today's proposal were based on 
our own assessment of the cellulosic biofuel industry, by the time we 
announce the final 2011 volumes and percentage standards we will have 
additional information. First, in addition to comments in response to 
today's proposal, we will have updated and more detailed information 
about how the industry is progressing in 2010. Second, by September 1 
all registered producers and importers of renewable fuel must submit 
Production Outlook Reports describing their expectations for new or 
expanded biofuel supply for the next five years, according to Sec.  
80.1449. Finally, by October 2010 the Energy

[[Page 42243]]

Information Administration (EIA) is required by statute to provide EPA 
with an estimate of the volumes of transportation fuel, biomass-based 
diesel, and cellulosic biofuel projected to be sold or introduced into 
commerce in the U.S. in 2011.

A. Cellulosic Biofuel

    The task of projecting the volume of cellulosic biofuels that will 
be produced in 2011 is a difficult one. Currently there are no 
facilities consistently producing cellulosic biofuels for commercial 
sale. Announcements of new projects, changes in project plans, project 
delays, and cancellations occur with great regularity. Biofuel 
producers face not only the challenge of the scale up of innovative, 
first-of-a-kind technology, but also the challenge of securing funding 
in a difficult economy.
    In order to project cellulosic biofuel production in 2011, EPA has 
tracked the progress of over 100 biofuel production facilities. From 
this list of facilities we used publicly available information, as well 
as information provided by DOE and USDA, to determine which facilities 
were the most likely candidates to produce cellulosic biofuel and make 
it commercially available in 2011. Each of these companies was 
contacted by EPA in order to determine the current status of their 
facilities and discuss their commercialization plans for the coming 
years. Our estimate of the maximum potentially available cellulosic 
biofuel production in 2011 is based on the information we received in 
conversations with these companies as well as our own assessment of the 
likelihood of these facilities successfully producing cellulosic 
biofuel in the volumes indicated.
    A brief description of each of the companies we believe may produce 
cellulosic biofuel and make it commercially available can be found 
below. These companies have been grouped according to the type of 
biofuel they produce. For the purpose of setting the cellulosic biofuel 
standard for 2011 this is a convenient grouping, as the number of RINs 
generated per gallon of fuel produced is dependent on the type of fuel. 
A more in depth discussion of the technologies used to produce 
cellulosic biofuels can be found in Section IV.
    In today's NPRM EPA is proposing a range, rather than a single 
value, for the required 2011 cellulosic biofuel volume. At a minimum, 
we believe that a volume of 6.5 million gallons could be justified 
based on currently available information. This is the cellulosic 
biofuel volume that was required in 2010, and absent a waiver for some 
portion of this volume, producers will be aiming to meet it. Therefore, 
it is reasonable to project that this same volume could, at minimum, 
also be produced in 2011.
    For a maximum potentially available cellulosic biofuel volume for 
2011, we are proposing 25.5 million ethanol equivalent gallons, 
representing the highest volume of fuel that can reasonably be expected 
to be produced and made available based on current information. In 
order for this volume of cellulosic biofuel to be produced in 2011, 
each of the companies discussed below would have to achieve their 
production targets in their projected timeframes. However, historical 
trends among cellulosic biofuel producers suggests that this is 
unlikely to be the case, as there are many factors which have the 
potential to result in production delays. For instance, several of the 
companies we considered when setting the 2010 cellulosic biofuel 
standard have yet to sell cellulosic biofuel in the United States and 
appear unlikely to do so by the end of 2010. This fact demonstrates the 
uncertainty of cellulosic biofuel production estimates, and is one of 
many factors EPA will consider when setting the cellulosic biofuel 
standard for 2011.
    The rest of this section describes the analyses that were used as 
the basis for this maximum value. We will continue to gather more 
information to help inform our decision on the final cellulosic biofuel 
standard for 2011, and we will specify a single volume in the final 
rule that will be the basis for the cellulosic biofuel percentage 
standard for 2011.
1. Domestic Cellulosic Ethanol
    Based on our assessment of the cellulosic biofuel industry we 
believe that there are five companies in the United States with the 
potential to produce cellulosic ethanol and make it commercially 
available in 2011. These companies are AE Biofuels, Agresti Biofuels, 
DuPont Danisco Cellulosic Ethanol, Fiberight, and KL Energy 
Corporation. This section will provide a brief description of each of 
these companies and our assessment of their potential fuel production 
in 2011. This section also provides a brief update on companies from 
whom we do not expect any commercial sales of transportation fuel in 
2011 in the U.S. but were included in prior assessments.
    AE Biofuels is a company that plans to convert corn cobs and corn 
stover to ethanol using an enzymatic hydrolysis. They plan to use an 
integrated process that converts both starch and cellulose to ethanol. 
In August 2008 they opened a demonstration plant in Butte, Montana to 
test their technology and gather information for their first commercial 
scale plant. AE Biofuels has reached a lease agreement with Cilion to 
operate Cilion's 55 MGY corn ethanol plant in Keyes, CA under the name 
AE Advanced Fuels Keyes. This facility has been idled since April 2009 
and will require repairs before being operational. AE Biofuels plans to 
start up production with a starch feedstock in late-2010 and then begin 
to transition some production to cellulosic feedstock in mid-2011. AE 
Biofuels plans to eventually use up to 25% cellulosic feedstock for 
ethanol production in this facility. EPA projects that up to 0.5 
million gallons of ethanol may be produced by this facility in 2011.
    Agresti Biofuels plans to produce ethanol from separated municipal 
solid waste (separated MSW) at a facility in Pike County, Kentucky. 
Their process uses a gravity pressure vessel licensed from GeneSyst to 
crack the lignin in their feedstock and then a combination of weak 
bases and acids to convert the cellulose and hemicellulose into simple 
sugars for later fermentation into ethanol. Agresti plans to begin 
construction on their first production facility in Pike County sometime 
in the summer of 2010 and hope to be producing ethanol by the end of 
2011. The full production capacity of this facility will be 20 million 
gallons of ethanol per year. Due to the fact that construction on this 
facility has not yet begun and production is not expected until late in 
2011 EPA expects no more than 1 million gallons of cellulosic ethanol 
to be produced by Agresti Biofuels in 2011.
    DuPont Danisco Cellulosic Ethanol (DDCE) began start up operations 
at a small demonstration facility in Vonore, Tennessee in early 2010. 
This facility has a maximum production capacity of 250,000 gallons of 
ethanol per year and uses an enzymatic hydrolysis process to convert 
corn cobs into ethanol. The main purpose of this facility is not to 
produce ethanol to be sold commercially, but rather to provide 
information for the future construction and optimization of larger, 
commercial scale cellulosic ethanol production facilities. DDCE have 
indicated that they do not intend to produce more than 150,000 gallons 
of ethanol in 2011 from the Vonore facility.
    Fiberight is another company planning to convert MSW to ethanol. 
Fiberight purchased a small corn ethanol plant in Blairstown, IA and 
has converted it to produce cellulosic ethanol. They use an enzymatic 
hydrolysis process, with enzymes

[[Page 42244]]

provided by Novozymes, to convert the cellulosic waste materials to 
simple sugars and eventually to ethanol. Fiberight has a unique enzyme 
recycle and recovery process that allows them to affordably use high 
concentrations of enzymes to increase the speed and conversion rate of 
the cellulose to simple sugars. Fiberight plans to begin ethanol 
production in the summer of 2010 and ramp up to full production 
capacity of 5.7 million gallons of ethanol per year by late 2011. Based 
on company estimates, EPA projects Fiberight could produce as much as 
2.8 million gallons of cellulosic ethanol in 2011.
    The fifth company that EPA is aware of with the potential to 
produce cellulosic ethanol in 2011 is KL Energy Corporation. KL Energy 
has a small facility in Upton, Wyoming that uses an enzymatic 
hydrolysis process to convert wood chips and wood waste to ethanol. 
This facility has a maximum annual production volume of 1.5 million 
gallons and has been operational since the fall of 2007. Since KL 
Energy completed construction on this facility they have been slowly 
ramping up production and gathering information to optimize this and 
future ethanol production facilities. KL has informed EPA that they 
intend to produce 400,000 gallons of cellulosic ethanol from their 
Upton, WY facility in 2011.
    In addition to the five companies mentioned above, EPA is also 
tracking the progress of more than 70 ethanol production facilities in 
various stages ranging from construction to planning stages. Several of 
these companies, including Abengoa, BlueFire Ethanol, Coskata, Fulcrum, 
POET, and Vercipia all intend to begin the production and commercial 
sale of cellulosic ethanol in 2012. These facilities range in maximum 
production capacity from 10 to 100 million gallons of ethanol. EPA 
anticipates a significant increase in the production and sale of 
cellulosic ethanol in 2012, and strong continued growth in the 
following years. In addition, if any of these or other companies 
accelerates their production plans to make cellulosic biofuel available 
for commercial sale in 2011, we will take those volumes into account in 
our final rule.
2. Domestic Cellulosic Diesel
    EPA is also aware of two companies in the United States with the 
potential of producing cellulosic diesel fuel in 2011. The first of 
these companies is Cello Energy. Cello Energy plans to use a catalytic 
depolymerization process to produce diesel fuel from wood chips and 
hay. Cello currently has a structurally complete facility in Bay 
Minette, Alabama with an annual production capacity of 20 million 
gallons of diesel per year. While having a structurally complete 
facility puts Cello ahead of many other potential biofuel producers 
they have yet to be able to produce biofuel at anywhere near the 
production capacity. They are currently assessing feedstock preparation 
and handling issues that must be resolved before they are able to again 
attempt start up and production at this facility. If these issues are 
successfully addressed EPA believes that Cello could, at most, produce 
up to 5 million gallons (8.5 million ethanol equivalent gallons) of 
cellulosic diesel fuel in 2011.
    Another potential producer of cellulosic biofuel in 2011 is Bell 
Bio-Energy. Bell Bio-Energy uses proprietary organisms to convert waste 
materials to liquid fuels and compost in a single step. The company 
currently has an agreement in place for the sale of the compost they 
produce and are searching for a location for their first plant and a 
partner to supply the waste materials they intend to use as feedstock. 
The liquid fuel they produce is not a finished transportation fuel, but 
could be upgraded to jet or diesel fuel. Bell Bio-Energy is currently 
working with a refining company to analyze the fuel they produce and 
determine the extent of upgrading necessary for the fuel to qualify as 
transportation fuel. They plan to begin construction on their first 
facility, which will have an annual fuel production capacity of 14.4 
million gallons per year, as soon as a suitable site and partner are 
found. The simplicity and low capital costs of Bell Bio-Energy's single 
step production process allow them to construct plants very rapidly, in 
as little as six weeks. This would make it possible for Bell Bio-Energy 
to produce cellulosic biofuel in 2011 despite the fact that they have 
not yet begun construction on their first commercial scale facility. It 
is unclear when fuel will be produced at this facility, and whether it 
would qualify under the RFS2 program. If Bell Bio-Energy is successful 
in producing and upgrading their fuel EPA estimates the maximum volume 
of fuel they could produce in 2011 would be 7 million gallons (11.9 
million ethanol equivalent gallons) of jet or diesel fuel.
    EPA is also tracking the progress of 17 other facilities that plan 
to produce cellulosic diesel. Flambeau Rivers Biofuels, New Page, and 
Terrabon are planning on opening commercial scale cellulosic diesel 
facilities in 2012. Both Bell Bio-Energy and Cello have plans to build 
additional facilities if their initial projects are successful. As with 
cellulosic ethanol, cellulosic diesel production has the potential for 
rapid growth in 2012 and the following years.
3. Other Domestic Cellulosic Biofuels
    We are currently unaware of any companies in the United States 
planning on producing cellulosic biofuel other than ethanol and diesel 
and making it commercially available. EPA is currently tracking the 
efforts of 10 companies that plan to produce fuels such as gasoline, 
jet fuel, dimethyl ether (DME), and others. Many of these companies 
have reported that they are still developing their technologies and 
waiting for funding, and that they are not expecting to make any 
cellulosic fuel commercially available until 2012 at the earliest. 
There are several companies, such as Gevo and Virent, with small 
demonstration facilities who intend to produce other fuels from 
cellulosic feedstocks, but are currently optimizing their technology 
with sugar or starch feedstocks. EPA anticipates that in the future 
this may be a significant source of cellulosic biofuel, however we are 
only expecting cellulosic ethanol and diesel to be produced in 2011.
4. Imports of Cellulosic Biofuel
    In addition to the companies located in the United States, EPA is 
also aware of two Canadian companies with the potential for cellulosic 
biofuel production in 2011. If this fuel was imported into the United 
States, these companies would be eligible to participate in the RFS2 
program. Counting on cellulosic biofuel produced internationally in 
setting the 2011 standard brings with it the additional uncertainty 
associated with the fact that the fuel may be used locally rather than 
imported into the United States.
    Iogen uses a steam explosion pre-treatment process followed by 
enzymatic hydrolysis to produce cellulosic ethanol from wheat, oat, and 
barley straw. They have a demonstration facility with an annual 
production capacity of 500,000 gallons of ethanol located in Ontario, 
Canada. This facility has been operational and producing small volumes 
of ethanol since 2004. So far all of the ethanol produced by this 
facility has been used locally and in racing and other promotional 
events. Iogen, however, is exploring the possibility of participating 
in the RFS2 program. If they do decide to import ethanol to the United 
States, EPA projects that they could provide as much as 250,000 gallons 
of cellulosic ethanol in 2011 based on production volumes from previous 
years.

[[Page 42245]]

    Another Canadian company with the potential to produce cellulosic 
ethanol in 2011 is Enerkem. Enerkem plans to use a thermo-chemical 
process to gasify separated MSW and other waste products and then use a 
catalyst to convert the synthesis (syn) gas into ethanol. Enerkem is 
currently finishing construction on a 1.3 million gallon per year 
facility in Westbury, Quebec and plans to begin producing ethanol in 
the summer of 2010. They are also planning a 10 million gallon per year 
facility in Edmonton, Alberta, however production from this facility is 
not expected until 2012. Enerkem has informed EPA that they plan to 
market ethanol they produce locally, and have no intentions to import 
cellulosic ethanol into the United States. We are therefore not 
projecting any available cellulosic fuel from Enerkem in 2011.
    While Canada may be the most likely source of imported cellulosic 
biofuels due to its close proximity, it is possible that cellulosic 
biofuels produced in other countries may be imported into the United 
States as well. Another potential source of cellulosic biofuel imports 
is Brazil, due to its established ethanol industry and history of 
importing ethanol into the United States. EPA is aware of several 
companies exploring the possibility of cellulosic biofuel production in 
Brazil; however none of these companies are likely to make cellulosic 
biofuels commercially available in the United States in 2011. With the 
exception of Iogen, as mentioned above, EPA has not projected imports 
of cellulosic biofuels from outside the United States in 2011.
5. Summary of Volume Projections
    The information EPA has gathered on the potential cellulosic 
biofuel producers in 2011, summarized in Section II.A above, allows us 
to project a maximum potentially available biofuel volume for each 
facility in 2011. After the appropriate ethanol equivalence value has 
been applied to the volumes of those facilities producing diesel fuel, 
the overall maximum potentially available volume of cellulosic biofuels 
for 2011 can be calculated by summing the maximum potential of each 
facility. EPA is not proposing to set the 2011 cellulosic biofuel 
standard at this maximum potentially available volume, rather this is 
intended to serve as an upper bound. This information is summarized in 
Table II.A.5-1 below.

                                      Table II.A.5-1--Cellulosic Biofuel Maximum 2011 Potentially Available Volume
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                           Maximum 2011
                                                                                                            Earliest        potentially       Ethanol
         Company name                Location          Feedstock           Fuel        Capacity (MGY)      production        available      equivalent
                                                                                                                            volume (MG)    gallons (MG)
--------------------------------------------------------------------------------------------------------------------------------------------------------
AE Advanced Fuels Keyes.......  Keyes, CA........  Corn, then        Ethanol.........              20  June 2011........             0.5             0.5
                                                    stover.
Agresti Biofuels..............  Pike County, KY..  MSW.............  Ethanol.........              20  Oct. 2011........               1               1
Bell Bio-Energy...............  Atlanta, GA......  MSW or other      Diesel Feedstock            14.4  June 2011........               7            11.9
                                                    cellulosic
                                                    biomass.
Cello Energy..................  Bay Minette, AL..  Wood, hay.......  Diesel..........              20  Online...........               5             8.5
DuPont Danisco \a\............  Vonore, TN.......  Corn cobs, then   Ethanol.........            0.25  Online...........            0.15            0.15
                                                    switchgrass.
Fiberight \a\.................  Blairstown, IA...  MSW.............  Ethanol.........               6  April 2010.......             2.8             2.8
Iogen.........................  Ottawa, Ontario..  Wheat, oat &      Ethanol.........             0.5  Online...........            0.25            0.25
                                                    barley straw.
KL Energy \a\.................  Upton, WY........  Wood............  Ethanol.........             1.5  Online...........             0.4             0.4
¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤
    Total.....................  .................  ................  ................  ..............  .................            17.1            25.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Maximum Production/Import Potential represents company estimate.

    It is important to note that this maximum potentially available 
volume of 17.1 million gallons of cellulosic biofuel, or 25.5 million 
ethanol equivalent gallons, is not the volume on which the final 2011 
cellulosic biofuel standard will be based. This number represents the 
maximum amount of fuel EPA believes could reasonably be expected to be 
produced or imported and made available for use as transportation fuel, 
heating oil, or jet fuel in 2011. It incorporates some reductions from 
the annual production capacity of each facility based on when the 
facilities anticipate fuel production will begin and assumptions 
regarding a ramp up period to full production. However, as stated 
earlier, in order for this volume of cellulosic biofuel to be produced 
in 2011, each of the companies listed in Table II.A.5-1 would have to 
achieve their production targets in their projected timeframes. The 
history of the cellulosic biofuels industry has many examples of delays 
in achieving full production capacity in new facilities. Also, there 
are many other factors that increase the uncertainty of fuel production 
facilities being able to achieve their maximum potential production. 
These factors may include:
     Difficulty/delays in securing necessary funding.
     Delays in permitting and/or construction.
     Difficulty in scale up, especially for 1st of their kind 
technologies.
     Volumes from pilot and demonstration plants may not be 
sold commercially.
     Not all feedstocks may qualify to produce cellulosic RINs; 
some still awaiting evaluation of lifecycle impacts.
     Likelihood that fuels produced internationally will be 
exported to the United States rather than consumed locally.
    Each of the facilities listed in Table II.A.5-1 may experience some 
of the difficulties listed above, and as a result may produce a volume 
of fuel less than that listed as their maximum 2011 potentially 
available volume. Despite this uncertainty, EPA believes that the 
volume of cellulosic biofuel produced in 2011 will, at minimum, be able 
to meet or exceed the 2010 standard of 6.5 million ethanol equivalent 
gallons. However, we will have more detailed and accurate information 
for the final rule, including the first round of Production Outlook 
Reports, due on

[[Page 42246]]

September 1, 2010 \5\ which will provide information from each producer 
or importer on the type or types of fuel they plan to make available, 
the volume of fuel, and the number of RINs they plan to generate for 
the next five calendar years.\6\ Therefore, in today's NPRM we are 
proposing a range of values, from a minimum of 6.5 million ethanol 
equivalent gallons to a maximum of 25.5 million ethanol equivalent 
gallons for the 2011 cellulosic biofuel standard. As time progresses 
and we are able to track whether or not the cellulosic biofuels 
producers are able to meet the construction and ramp up schedules they 
have presented, we will have a better idea of the appropriate volume of 
fuel that we can reasonably expect to be produced and made commercially 
available in 2011. Additionally, each year by October 31 EIA is 
required to provide an estimate of the volume of cellulosic biofuel 
they expect to be sold or introduced into commerce in the United States 
in the following year. EPA will consider this information as well when 
finalizing a single volume for use in setting the 2011 cellulosic 
biofuel standard.
---------------------------------------------------------------------------

    \5\ In future years, Production Outlook Reports will be due on 
March 1. As a result, they may be considered during development of 
the NPRM in year 2011 and beyond.
    \6\ For more information on the annual production outlook 
reports see Sec.  80.1449 of the RFS2 regulations.
---------------------------------------------------------------------------

    Although we are currently projecting that the potentially available 
volume of cellulosic biofuel in 2011 will be in the range of 6.5 to 
25.5 million ethanol-equivalent gallons, we expect that volumes of 
cellulosic biofuel will increase rapidly in the years following 2011. 
As stated before, we are aware of more than 100 companies that are 
actively investigating or making plans to produce cellulosic biofuel in 
the near future. Many of these companies intend to begin construction 
in 2011 or 2012. We will be monitoring these companies carefully as we 
project the potential volumes of cellulosic biofuel for years 2012 and 
beyond.

B. Potential Limitations

    In addition to production capacity, a variety of other factors have 
the potential to limit the amount of cellulosic biofuel that can be 
produced and used in the U.S. For instance, there may be limitations in 
the availability of qualifying cellulosic feedstocks at reasonable 
prices. Most of the cellulosic biofuel producers that we project will 
produce commercial volumes in 2011 have indicated that they will use 
some type of cellulosic waste, such as separated municipal solid waste, 
wastes from the forestry industry, and agricultural residues. Based on 
the analyses of cellulosic feedstock availability in the RFS2 final 
rule, we believe that there will be significantly more than enough 
sources of these feedstocks for 2011. For producers that intend to use 
dedicated energy crops, we do not believe that the availability of 
existing cropland will limit production in 2011. We plan to continue to 
evaluate the availability of valid feedstocks in future years as the 
required volumes of cellulosic biofuel increase.
    Another factor that has the potential to limit the amount of 
renewable fuel that can be produced and used in the U.S. is 
distribution and storage capacity. In the longer term, most biofuels 
are expected to be produced in the heartland of the country and then be 
shipped towards the coasts, flowing roughly in the opposite direction 
of petroleum-based fuels. The physical and chemical nature of many of 
these biofuels may limit the extent to which they can be shipped and/or 
stored fungibly with petroleum-based fuels. As a result, new and 
expanded rail, barge and tank truck transport will need to be put in 
place. Dedicated biofuels pipelines are also being investigated. For 
instance, a short gasoline pipeline in Florida is currently shipping 
batches of ethanol.\7\ Evaluations are also currently underway 
regarding the feasibility of constructing a new dedicated ethanol 
pipeline from the Midwest to the East coast.\8\ However, for 2011 the 
volumes of cellulosic biofuel are small enough that long-distance 
transport will be unnecessary; with the exception of foreign-produced 
biofuels, much of the cellulosic biofuel volumes can be consumed in 
regions close to their production facilities. We also expect existing 
distribution and storage capacity to be sufficient to accommodate the 
small increase in cellulosic biofuel volumes in 2011.
---------------------------------------------------------------------------

    \7\ Kinder Morgan announcement that their Central Florida 
Pipeline from Tampa to Orlando ships batches of ethanol along with 
batches of gasoline. http://www.kindermorgan.com/business/products_
pipelines/.
    \8\ ``POET Joins Magellan Midstream Partners to Assess Dedicated 
Ethanol Pipeline'', March 2009, http://www.poet.com/news/
showRelease.asp?id=155.
---------------------------------------------------------------------------

C. Advanced Biofuel and Total Renewable Fuel

    Under CAA 211(o)(7)(D)(i), EPA has the flexibility to reduce the 
applicable volume of the advanced biofuel and total renewable fuel 
requirements in the event that the projected volume of cellulosic 
biofuel is determined to be below the volume specified in the statute. 
As described in Section II.A above, even the largest potential volumes 
of cellulosic biofuel supply for 2011 are significantly below the 
statutory volume of 250 million gallons. Therefore, we must consider 
whether and to what degree to lower the advanced biofuel and total 
renewable fuel standards for 2011.
    As described in the RFS2 final rule, we believe it may be 
appropriate to allow excess advanced biofuels to make up some or all of 
the shortfall in cellulosic biofuel. This could include excess biomass-
based diesel, sugarcane ethanol, or other biofuels categorized as 
advanced biofuel. We believe that Congress wanted to encourage the 
development of advanced renewable fuels and allow in appropriate 
circumstances for the use of additional volumes of those fuels in the 
event that the projected volume of cellulosic biofuel falls below the 
statutory mandate.
    If we were to maintain the advanced biofuel and total renewable 
fuel volume requirements at the levels specified in the statute, we 
estimate that 125-144 million ethanol-equivalent gallons of additional 
advanced biofuels would be needed, depending on the standard we set for 
cellulosic biofuel. See Table II.C-1.

   Table II.C-1--Projected Impact of Cellulosic Volume on Use of Other
                            Biofuels in 2011
                             [Mill gallons]
------------------------------------------------------------------------
                                                  Ethanol-
                                                 equivalent    Physical
                                                   volume       volume
------------------------------------------------------------------------
Total renewable fuel..........................       13,950  13,500-13,5
                                                                      49
Conventional renewable fuel \a\...............       12,600       12,600
Total advanced biofuel........................        1,350      900-949
Cellulosic biofuel............................     6.5-25.5       5-17.1
Biomass-based diesel..........................         1200          800
Other advanced biofuel \b\....................      125-144   83 \c\-144
                                                                     \d\
------------------------------------------------------------------------
\a\ Predominantly corn-starch ethanol.
\b\ Rounded to nearest million gallons for simplicity.
\c\ Lowest volume of other advanced biofuel assumes cellulosic biofuel
  standard is based on 25.5 mill gallons and only excess biodiesel (with
  an equivalence value (EV) of 1.5) is used to fill the need for other
  advanced biofuel.
\d\ Highest volume of other advanced biofuel assumes cellulosic biofuel
  standard is based on 6.5 mill gallons and only imported sugarcane
  ethanol (with an EV of 1.0) is used to fill the need for other
  advanced biofuel.


[[Page 42247]]

    To determine if there are likely to be sufficient volumes of 
imported sugarcane ethanol and/or excess biodiesel to meet the need for 
125-144 million gallons of other advanced biofuel, we examined 
historical data on ethanol imports and EIA projections for 2011. For 
instance, as shown in Table II.C-2 below, recent annual import volumes 
of ethanol were higher than what would be needed in 2011.

               Table II.C-2--Historical Imports of Ethanol
                           [Mill gallons] \9\
------------------------------------------------------------------------

------------------------------------------------------------------------
2007...........................................................      439
2008...........................................................      530
2009...........................................................      194
------------------------------------------------------------------------

Brazilian imports have made up a sizeable portion of total ethanol 
imported into the U.S. However, as shown above, these import volumes 
decreased significantly in 2009. Part of the reason for this decline in 
imports is the cessation of the duty drawback that became effective on 
October 1, 2008, but also changes in world sugar prices.\10\ However, 
Brazil produces the most ethanol in the world, reaching about 9 billion 
gallons in 2008.\11\ Thus if there were a demand in the U.S. in 2011 
for 125-144 million gallons of advanced biofuel, it may be economical 
for Brazil to export at least this volume of sugarcane ethanol to the 
U.S.
---------------------------------------------------------------------------

    \9\ ``Monthly U.S. Imports of Fuel Ethanol,'' EIA, released 4/8/
2010.
    \10\ Lundell, Drake, ``Brazilian Ethanol Export Surge to End; 
U.S. Customs Loophole Closed Oct. 1,'' Ethanol and Biodiesel News, 
Issue 45, November 4, 2008.
    \11\ Renewable Fuels Association (RFA), ``2008 World Fuel 
Ethanol Production,'' http://www.ethanolrfa.org/industry/statistics/
#E, March 31, 2009.
---------------------------------------------------------------------------

    EIA's projections for 2011 suggest that there may be sufficient 
volumes of imported sugarcane ethanol and excess biodiesel production 
to make up for our proposed reduction in the required volume of 
cellulosic biofuel. See Table II.C-3.

 Table II.C-3--EIA Projected Imported Ethanol and Biodiesel Availability
                                 in 2011
                           [Mill gallons] \12\
------------------------------------------------------------------------

------------------------------------------------------------------------
Imported ethanol...............................................      202
Total domestic biodiesel production............................      860
Biodiesel needed to meet biomass-based diesel standard.........      800
Excess biodiesel...............................................       60
------------------------------------------------------------------------

Further discussion of the potential availability of biomass-based 
diesel in 2011 can be found in the next Section II.D below.
---------------------------------------------------------------------------

    \12\ EIA STEO, June 2010, Table 8.
---------------------------------------------------------------------------

    Based on these projections, there would be a total of 60 million 
gallons of excess biodiesel production (90 million gallons ethanol-
equivalent), plus another 202 million gallons of imported sugarcane 
ethanol. The total would therefore be 292 million gallons ethanol-
equivalent. Since we are projecting that the need for other advanced 
biofuel would be in the range of 125-144 million gallons depending on 
the cellulosic biofuel standard that we set, 292 million gallons would 
likely be sufficient. Moreover, the projections in Table II.C-3 do not 
account for other potential sources of advanced biofuels. For instance, 
California's Low Carbon Fuel Standard goes into effect in 2011, and may 
compel some refiners to import additional volumes of sugarcane ethanol 
from Brazil into California. These same volumes could count towards the 
Federal RFS2 program as well. There may also be other types of advanced 
biofuel not included in the EIA projections that could help meet our 
projected shortfall. These other advanced biofuels include, for 
instance, renewable fuels made from separated yard and food waste such 
as waste cooking oil or restaurant grease used as a diesel fuel 
additive. Finally, additional market demand for imported sugarcane 
ethanol and biodiesel would likely be created if we chose not to lower 
the advanced biofuel standard for 2011. Given these factors, we believe 
that there are likely to be sufficient volumes of other advanced 
biofuels such that the advanced biofuel standard need not be lowered 
below 1.35 billion gallons. Thus, we are proposing to leave the 
required volume of advanced biofuel for 2011 at 1.35 billion gallons. 
Nevertheless, we request comment on whether we should lower the 
advanced biofuel standard. If we do lower the advanced biofuel 
standard, we request comment on the degree to which we should take into 
account other potential sources of advanced biofuel as discussed above.
    If we lower the cellulosic biofuel standard, we would also need to 
determine if the total renewable standard should be lowered. Lowering 
both the advanced biofuel standard and the total renewable fuel 
standard by the same amount would mean that the expected amount of 
conventional renewable fuel use, such as corn-ethanol, would remained 
unchanged at 12,600 million gallons ethanol equivalent, the same as 
shown in Table II.C-1.
    If instead we were to lower the advanced biofuel standard but 
retain the total renewable fuel standard at 13,950 million gallons, 
then we would expect the use of conventional renewable fuels such as 
corn ethanol to increase. For instance, if we were to lower the 
advanced biofuel standard by 144 million gallons to 1,206 million 
gallons, we would expect the amount of corn-ethanol used would increase 
by 144 million gallons in order to satisfy the total renewable fuel 
standard of 13,950 million gallons. According to EIA, projected volumes 
of corn-ethanol are indeed expected to be higher than 12,600 million 
gallons in 2011, producing an excess of 1050 million gallons. See Table 
II.C-4.

           Table II.C-4--Projected Excess Corn Ethanol in 2011
                             [Mill gallons]
------------------------------------------------------------------------

------------------------------------------------------------------------
Total domestic corn ethanol production \13\....................   13,650
Corn ethanol needed to meet total renewable fuel standard......   12,600
Excess corn ethanol............................................     1050
------------------------------------------------------------------------
\13\ EIA STEO, June 2010, Table 8.

    However, the market potential for ethanol in the U.S. is also a 
function of the ethanol blender's tax credit, set to expire at the end 
of 2010. If this tax credit is not renewed, the excess ethanol volume 
shown in Table II.C-4 may be smaller. Thus, while we are proposing that 
the required volume of total renewable fuel for 2011 be set at the 
statutory level of 13.95 billion gallons, we request comment on whether 
the total renewable fuel standard should be lowered.

D. Biomass-Based Diesel

    While the statutory requirement that we project volumes of 
cellulosic biofuel for next year does not explicitly apply to biomass-
based diesel as well, there are two other statutory requirements that 
compel us to investigate current and potential future volumes of 
biomass-based diesel. First, the Clean Air Act provides limited waiver 
authority specific to biomass-based diesel under 211(o)(7)(E) if a 
significant renewable feedstock disruption or other market circumstance 
would make the price of biomass-based diesel fuel increase 
significantly. Second, as described more fully in Section II.C above, 
we must determine whether the required volumes of advanced biofuel and/
or total renewable fuel should be reduced at the same time that we 
reduce the required volume of cellulosic biofuel. The amount of 
biomass-based diesel that we project can be available

[[Page 42248]]

will directly affect our consideration of adjustments to the volumetric 
requirements for advanced biofuel and total renewable fuel.
    To project biodiesel production volumes for 2011, we examined both 
production capacity of the industry as well as actual recent production 
rates. As of April 2010, the aggregate production capacity of biodiesel 
plants in the U.S. was estimated at 2.2 billion gallons per year across 
approximately 137 facilities.\14\ Biodiesel production for calendar 
year 2009, according to the most recently available information, was 
540 million gallons, with an estimated 351 mill gallons (or 65%) being 
used domestically. Domestic production rates in the second half of 2009 
increased above production rates in the first half as economic 
conditions improved, to an annualized rate of around 646 mill gal per 
year. Meanwhile, exports appeared to stabilize at an annualized rate of 
about 242 mill gal per year, after recovering from changes in European 
import regulations early in the year. These trends for 2009 are shown 
in Figure II.D-1.
---------------------------------------------------------------------------

    \14\ Figures taken from National Biodiesel Board list of 
operating plants as of April 5, 2010.
    \15\ Data taken from Energy Information Administration Monthly 
Energy Review, Table 10.4, March 2010.
[GRAPHIC] [TIFF OMITTED] TP20JY10.000

    In the early part of 2010, industry reports of monthly biodiesel 
production indicated that production rates have dropped below the 2009 
average. The most likely cause is the expiration of the biodiesel tax 
credit. However, EIA's Short-Term Energy Outlook projects that, for the 
year as a whole, average monthly biodiesel production rates in 2010 
will actually exceed those in 2009. The projected increase in monthly 
biodiesel production rates later in 2010 is consistent with the fact 
that obligated parties are not required to demonstrate compliance with 
the 2010 biomass-based diesel volume requirement of 1.15 billion 
gallons until February 28, 2011. For development of our final rule 
setting the standards for 2011, we will have more complete data with 
which to evaluate the progress of the biodiesel industry in meeting the 
2010 volume mandate and thus its preparedness for 2011.
    In order to meet a 2011 biomass-based diesel volume requirement of 
0.8 billion gallons to be consumed in the United States, the biodiesel 
industry will need to produce approximately 725 million gal of fuel. 
This value accounts for the production of 75 million gallons of 
renewable diesel at one renewable diesel facility in Geismar, 
Louisiana, set to begin operations later this year.\16\ Assuming 
imports and exports continue at a rate equivalent to that in the second 
half of 2009, biodiesel production in the U.S. would need to total 
approximately 900 million gal in 2011. While this production rate would 
be about 10% higher than the production rate projected by EIA for the 
second half of 2010, it would be significantly lower than the current 
2.2 billion gallon biodiesel production capacity of the industry. 
Indications from the biodiesel industry are that these idled facilities 
can be brought back into production with a relatively short leadtime, 
and can thus meet the 2011 requirements for biomass-based diesel. 
Moreover, as shown in Table II.C-3, EIA is projecting that biodiesel 
availability will in fact exceed the minimum volume needed to meet the 
biomass-based diesel standard in 2011.
---------------------------------------------------------------------------

    \16\ Project status updates are available via the Syntroleum Web 
site, http://dynamicfuelsllc.com/wp-news/.
---------------------------------------------------------------------------

    Finally, we believe that there will be sufficient sources of 
qualifying renewable biomass to meet the needs of the biodiesel 
industry in 2011. The largest sources of feedstock for biodiesel in 
2011 are expected to be soy oil, rendered fats, and potentially some 
corn

[[Page 42249]]

oil extracted during production of fuel ethanol, as this technology 
continues to proliferate. Moreover, comments we received from a large 
rendering company after the May 2009 RFS2 proposed rule suggest that 
there will be adequate fats and greases feedstocks to supply biofuels 
production as well as other historical uses.\17\
---------------------------------------------------------------------------

    \17\ See Federal Register v.74 n.99 p.24903. Comments are 
available in docket EPA-HQ-OAR-2005-0161.
---------------------------------------------------------------------------

III. Proposed Percentage Standards for 2011

A. Background

    The renewable fuel standards are expressed as a volume percentage, 
and are used by each refiner, blender or importer to determine their 
renewable volume obligations (RVO). Since there are four separate 
standards under the RFS2 program, there are likewise four separate RVOs 
applicable to each obligated party. Each standard applies to the sum of 
all gasoline and diesel produced or imported. The applicable percentage 
standards are set so that if each regulated party meets the 
percentages, then the amount of renewable fuel, cellulosic biofuel, 
biomass-based diesel, and advanced biofuel used will meet the volumes 
required on a nationwide basis.
    As discussed in Section II.A.5, we are proposing a required volume 
of cellulosic biofuel for 2011 in the range of 5-17.1 million gallons 
(6.5-25.5 million ethanol equivalent gallons). The single volume we 
select for the final rule will be used as the basis for setting the 
percentage standard for cellulosic biofuel for 2011. We are also 
proposing that the advanced biofuel and total renewable fuel volumes 
would not be reduced below the statutory requirements. The proposed 
2011 volumes used to determine the four percentage standards are shown 
in Table III.A-1.

                                    Table III.A-1--Proposed Volumes for 2011
----------------------------------------------------------------------------------------------------------------
                                                   Actual volume                Ethanol equivalent volume
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel.......................  5-17.1 mill gal.............  6.5-25.5 mill gal.
Biomass-based diesel.....................  0.80 bill gal...............  1.20 bill gal.
Advanced biofuel.........................  1.35 bill gal...............  1.35 bill gal.
Renewable fuel...........................  13.95 bill gal..............  13.95 bill gal.
----------------------------------------------------------------------------------------------------------------

    The formulas used in deriving the annual renewable fuel standards 
are based in part on an estimate of combined gasoline and diesel 
volumes, for both highway and nonroad uses, for the year in which the 
standards will apply. Producers of other transportation fuels, such as 
natural gas, propane, and electricity from fossil fuels, are not 
subject to the standards. Since the standards apply to producers and 
importers of gasoline and diesel, these are the transportation fuels 
used to set the standards, and then again to determine the annual 
volume obligations of an individual producer or importer.

B. Calculation of Standards

1. How are the standards calculated?
    The following formulas are used to calculate the four percentage 
standards applicable to producers and importers of gasoline and diesel 
(see Sec.  80.1405):
[GRAPHIC] [TIFF OMITTED] TP20JY10.001

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

[[Page 42250]]

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 Sec. Sec.  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 Sec. Sec.  80.1441 and 80.1442, 
respectively. For 2011, this value is zero. See further discussion 
in Section III.B.2 below.

    The four separate renewable fuel standards for 2011 are based on 
the 49-state gasoline and diesel consumption volumes projected by EIA. 
The Act requires EPA to base the standards on an EIA estimate of the 
amount of gasoline and diesel that will be sold or introduced into 
commerce for that year. The projected volume of gasoline used to 
calculate the final percentage standards will continue to be provided 
by the October issue of EIA's Short-Term Energy Outlook (STEO). For the 
purposes of this proposal, we have used the March 2010 issue of STEO. 
The projected volume of transportation diesel used to calculate the 
final percentage standards will be provided by the most recent Annual 
Energy Outlook (AEO). For the purposes of this proposal, we have used 
the Early Release version of AEO2010. Gasoline and diesel volumes are 
adjusted to account for renewable fuel contained in the EIA 
projections. Beginning in 2011, gasoline and diesel volumes produced by 
small refineries and small refiners are not exempt, and thus there is 
no adjustment to the gasoline and diesel volumes in today's proposal to 
account for such an exemption, as there has been in past years. 
However, as discussed more fully in Section III.B.2 below, depending 
upon the results of a Congressionally-mandated DOE study, it is 
possible that the exemption for gasoline and diesel volumes produced by 
small refineries and small refiners may be extended. In addition, EPA 
may extend the exemption for individual small refineries on a case-by-
case basis if they demonstrate disproportionate economic hardship.
    As finalized in the March 26, 2010 RFS2 rule, the standards are 
expressed in terms of energy-equivalent gallons of renewable fuel, with 
the cellulosic biofuel, advanced biofuel, and total renewable fuel 
standards based on ethanol equivalence and the biomass-based diesel 
standard based on biodiesel equivalence. However, all RIN generation is 
based on ethanol-equivalence. More specifically, the RFS2 regulations 
provide that production or import of a gallon of biodiesel will lead to 
the generation of 1.5 RINs. In order to ensure that demand for 0.8 
billion physical gallons of biomass-based diesel will be created in 
2011, the calculation of the biomass-based diesel standard provides 
that the required volume be multiplied by 1.5. The net result is a 
biomass-based diesel gallon being worth 1.0 gallons toward the biomass-
based diesel standard, but worth 1.5 gallons toward the other 
standards.
    The levels of the percentage standards would be reduced if Alaska 
or a U.S. territory chooses to participate in the RFS2 program, as 
gasoline and diesel produced in or imported into that state or 
territory would then be subject to the standard. Neither Alaska nor any 
U.S. territory has chosen to participate in the RFS2 program at this 
time, and thus the value of the related terms in the calculation of the 
standards is zero.
    Note that the terms for projected volumes of gasoline and diesel 
use include gasoline and diesel that has been blended with renewable 
fuel. Because the gasoline and diesel volumes described above include 
renewable fuel use, we must subtract the total renewable fuel volume 
from the total gasoline and diesel volume to get total non-renewable 
gasoline and diesel volumes. The values of the variables described 
above are shown in Table III.B.1-1. Terms not included in this table 
have a value of zero.

    Table III.B.1-1--Values for Terms in Calculation of the Standards
                             [Bill gallons]
------------------------------------------------------------------------
                      Term                                Value
------------------------------------------------------------------------
RFVCB,2011.....................................            0.0065-0.0255
RFVBBD,2011....................................                     0.80
RFVAB,2011.....................................                     1.35
RFVRF,2011.....................................                    13.95
G2011..........................................                   139.66
D2011..........................................                    50.01
RG2011.........................................                    13.38
RD2011.........................................                     0.74
------------------------------------------------------------------------

    Using the volumes shown in Table III.B.1-1, we have calculated the 
proposed percentage standards for 2011 as shown in Table III.B.1-2.

         Table III.B.1-2--Proposed Percentage Standards for 2011
------------------------------------------------------------------------

------------------------------------------------------------------------
Cellulosic biofuel....................................      0.004-0.015%
Biomass-based diesel..................................             0.68%
Advanced biofuel......................................             0.77%
Renewable fuel........................................             7.95%
------------------------------------------------------------------------

2. Small Refineries and Small Refiners
    In CAA section 211(o)(9), enacted as part of EPAct, Congress 
provided a temporary exemption to small refineries (those refineries 
with a crude throughput of no more than 75,000 barrels of crude per 
day) through December 31, 2010. In RFS1, we exercised our discretion 
under section 211(o)(3)(B) and extended this temporary exemption to the 
few remaining small refiners that met the Small Business 
Administration's (SBA) definition of a small business (1,500 employees 
or less company-wide) but did not meet the statutory small refinery 
definition as noted above. Because EISA did not alter the small 
refinery exemption in any way, the RFS2 program regulations exempt 
gasoline and diesel produced by small refineries and small refiners in 
2010 from the renewable fuels standard (unless the exemption was 
waived), see 40 CFR Sec.  80.1141.
    Under the RFS program, Congress has provided two ways that small 
refineries can receive a temporary extension of the exemption beyond 
2010. One is based on the results of a study conducted by

[[Page 42251]]

the Department of Energy (DOE) to determine if small refineries would 
face a disproportionate economic hardship under the RFS program. The 
other is based on EPA determination of disproportionate economic 
hardship on a case-by-case basis in response to refiner petitions.
    In January 2009, DOE issued a Small Refineries Exemption Study 
which did not find that small refineries would face a disproportionate 
economic hardship under the RFS program. The conclusions were based in 
part on the expected robust availability of RINs and EPA's ability to 
grant relief on a case-by-case basis. Subsequently, Congress directed 
DOE to complete a reassessment and issue a revised report by June 30, 
2010. DOE had not revised its study at the time of the RFS2 final 
rulemaking nor at the time of this writing. Additionally, we have not 
received any requests for relief on a case-by-case basis from any small 
refinery. If DOE prepares a revised study, and the results of that 
study show a disproportionate economic hardship for any small 
refineries under the RFS program, we will take appropriate action to 
extend the exemption. However, until and unless a DOE study supporting 
an extension to the temporary exemption for small refineries beyond 
2010 is used, or any petitions to EPA from individual small refineries 
claiming disproportionate economic hardship are approved, we are not 
proposing to change the required inclusion of small refineries and 
small refiners in the RFS2 program beginning with the 2011 compliance 
period.

IV. Cellulosic Biofuel Technology Assessment

    In projecting the volumes of cellulosic biofuel for 2011, we 
conducted a technical assessment of the production technologies that 
are under consideration by the broad universe of companies we 
investigated. Many of these companies are still in the research phase, 
resolving outstanding issues with specific technologies, and/or in the 
design phase to implement those technologies for the production of 
commercial-scale volumes of cellulosic biofuel. A subset of the 
companies we investigated have moved beyond the research and design 
phase and are actively preparing for production. This smaller group of 
companies formed the basis for our projection of potential 2011 volumes 
of cellulosic biofuel.
    This section discusses the full range of cellulosic biofuel 
technologies being considered among producers, with reference to those 
individual companies that are focusing on each technology and those we 
project will be most likely to use those technologies to produce 
cellulosic biofuel in 2011.

A. What pathways are valid for the production of cellulosic biofuel?

    In determining the appropriate volume of cellulosic biofuel on 
which to base the percentage standard for 2011, we must ensure that the 
production facilities we use as the basis for this volume are using 
fuel pathways that are valid for the production of cellulosic biofuel. 
In general this means that each facility's pathway (combination of 
feedstock, production process, and fuel type) must be included in Table 
1 to Sec.  80.1426 and be assigned a D code of either 3 or 7. As of 
this writing, there are three valid pathways available as shown in 
Table IV.A-1 below.

                      Table IV.A-1--Cellulosic Biofuel Pathways for Use in Generating RINs
----------------------------------------------------------------------------------------------------------------
                                                           Production process
            Fuel type                    Feedstock            requirements                   D-Code
----------------------------------------------------------------------------------------------------------------
Ethanol.........................  Cellulosic Biomass from  Any...............  3 (cellulosic biofuel).
                                   agricultural residues,
                                   slash, forest
                                   thinnings and forest
                                   product residues,
                                   annual covercrops;
                                   switchgrass, and
                                   miscanthus; cellulosic
                                   components of
                                   separated yard wastes;
                                   cellulosic components
                                   of separated food
                                   wastes; and cellulosic
                                   components of
                                   separated MSW.
Cellulosic Diesel, Jet Fuel and   Cellulosic Biomass from  Any...............  7 (cellulosic diesel).
 Heating Oil.                      agricultural residues,
                                   slash, forest
                                   thinnings and forest
                                   product residues,
                                   annual covercrops,
                                   switchgrass, and
                                   miscanthus; cellulosic
                                   components of
                                   separated yard wastes;
                                   cellulosic components
                                   of separated food
                                   wastes; and cellulosic
                                   components of
                                   separated MSW.
Cellulosic Naphtha..............  Cellulosic Biomass from  Fischer-Tropsch     3 (cellulosic biofuel).
                                   agricultural residues,   process.
                                   slash, forest
                                   thinnings and forest
                                   product residues,
                                   annual covercrops,
                                   switchgrass, and
                                   miscanthus; cellulosic
                                   components of
                                   separated yard wastes;
                                   cellulosic components
                                   of separated food
                                   wastes; and cellulosic
                                   components of
                                   separated MSW.
----------------------------------------------------------------------------------------------------------------

    Of the eight facilities that we currently believe could contribute 
to the volume of commercially available cellulosic biofuel in 2011, six 
would produce ethanol from cellulosic biomass and two would produce 
diesel from cellulosic biomass. None of the facilities we have 
evaluated would produce cellulosic naphtha through a Fischer-Tropsch 
process.
    Two of the facilities shown in Table II.A.5-1, Cello Energy and KL 
Energy, intend to use wood as the primary feedstock. The only types of 
wood that are currently 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 Sec.  80.1426. However, as described more fully in Section 
V.A, we are currently evaluating the lifecycle GHG impacts of biofuel 
made from pulpwood, including wood from tree plantations. If such a 
pathway is determined to meet the 60% GHG threshold required for 
cellulosic biofuel, we expect that it will be added to Table 1 to Sec.  
80.1426 in time to apply to fuel produced in 2011. For the purposes of 
this proposal, we have chosen to retain the volumes from these two 
companies in our projections of 2011 cellulosic biofuel volume, but we 
will revisit this issue for the final rule.

B. Cellulosic Feedstocks

    Cellulosic biofuel technologies are different from other biofuel 
technologies because they convert the cellulose and

[[Page 42252]]

other very difficult to convert compounds into biofuels. Unlike grain 
feedstocks where the major carbohydrate is starch (very simply combined 
sugars), lignocellulosic biomass is composed mainly of cellulose (40-
60%) and hemicellulose (20-40%).\18\ Cellulose and hemicellulose are 
made up of sugars linked together in long chains called 
polysaccharides. Once hydrolyzed, they can be fermented into ethanol. 
Most all the remainder of cellulosic feedstocks consists of lignin, a 
complex polymer which serves as a stiffening and hydrophobic (water-
repelling) agent in cell walls. Currently, lignin cannot be fermented 
into ethanol, but could be burned as a by-product to generate 
electricity. Thermochemical, pyrolysis and depolymerization processing, 
however, can convert some or even most of the lignin, in addition to 
the cellulosic and hemicellulose, into biofuels.
---------------------------------------------------------------------------

    \18\ DOE. ``Biomass Program: ABC's of Biofuels''. Accessed at: 
http://www1.eere.energy.govbiomass/abcs_biofuels.html#content.
---------------------------------------------------------------------------

C. Emerging Technologies

    When evaluating the array of biofuel technologies which could 
produce one or more fuels from cellulose that could qualify under RFS2, 
we found that it is helpful to organize them into fuel technology 
categories. Organizing them into categories eases the task of 
understanding the technologies, and also simplifies our understanding 
of the costs and lifecycle impacts of these technologies because 
similar technologies likely have similar cost and lifecycle impacts. 
The simplest organization is by the fuel produced. However, we 
frequently found that additional subdivisions were also helpful. Table 
IV.C-1 provides a list of technologies, the cellulosic fuels produced 
and a list of many of the companies which we learned are pursuing the 
technology (or something very similar to the technology listed in the 
category).

    Table IV.C-1--List of Technology Categories, the Fuels Produced Through Each Type of Technology, and the
                                             Companies Pursuing Them
----------------------------------------------------------------------------------------------------------------
        Technology category                 Technology              Fuels produced             Companies
----------------------------------------------------------------------------------------------------------------
Biochemical.......................  Enzymatic Hydrolysis......  Ethanol..............  Abengoa, AE Fuels, DuPont
                                                                                        Danisco, Florida
                                                                                        Crystals, Gevo, Poet,
                                                                                        ICM, Iogen, BPI, Energy,
                                                                                        Fiberight, KL Energy.
                                    Acid Hydrolysis...........  Ethanol..............  Agresti, Arkenol, Blue
                                                                                        Fire, Pencor, Pangen,
                                                                                        Raven Biofuels.
                                    Dilute Acid, Steam          Ethanol..............  Verenium, BP, Central
                                     Explosion of Cellulose.                            Minnesota Ethanol Coop.
                                    Consolidated Bioprocessing  Ethanol..............  Mascoma, Qteros.
                                     (one step hydrolysis and
                                     fermentation) of
                                     Cellulose.
                                    Conversion of Cellulose     Ethanol, Gasoline,     Terrabon, Swift Fuels.
                                     via carboxylic acid.        Jet Fuel, Diesel
                                                                 Fuel.
                                    One step Conversion of      Diesel, Jet Fuel or    Bell Bioenergy, LS9.
                                     Cellulose to distillate.    Naphtha.
Thermochemical....................  Thermochemical/Fischer      Diesel Fuel and        Choren, Flambeau River
                                     Tropsch.                    Naphtha.               Biofuels, Baard,
                                                                                        Clearfuels, Gulf Coast
                                                                                        Energy, Rentech, TRI.
                                    Thermochemical/Fischer      DME..................  Chemrec, New Page.
                                     Tropsch.
                                    Thermochemical/Catalytic    Ethanol..............  Range Fuels, Pearson
                                     conversion of syngas to                            Technologies, Fulcrum
                                     alcohols.                                          Bioenergy, Enerkem, and
                                                                                        Gulf Coast Energy.
Hybrid............................  Thermochemical w/           Ethanol..............  Coskata, INEOS Bio.
                                     Biochemical catalyst.
                                    Acid Hydrolysis of          Ethanol, Other         Zeachem.
                                     cellulose to                alcohols.
                                     intermediate;
                                     hydrogenation using
                                     Thermochemical syngas
                                     from non-cellulose
                                     fraction.
Depolymerization..................  Catalytic Depolymerization  Diesel, Jet Fuel or    Cello Energy.
                                     of Cellulose.               Naphtha.
                                    Pyrolysis of Cellulose....  Diesel, Jet Fuel, or   Envergent (UOP/Ensyn),
                                                                 Gasoline.              Dynamotive, Petrobras,
                                                                                        Univ. of Mass, KIOR.
Other.............................  Catalytic Reforming of      Gasoline.............  Virent.
                                     Sugars from Cellulose.
----------------------------------------------------------------------------------------------------------------

    Of the technologies listed above, many of them are considered to be 
``second generation'' biofuels or new biofuel technologies capable of 
meeting either the advanced biofuel or cellulosic biofuel RFS standard. 
The following sections describe specific companies and the new biofuel 
technologies which the companies have developed or are developing. This 
summary is not meant to be an unabridged list of new biofuel 
technologies, but rather a description of some of the more prominent of 
the new biofuel technologies that serve to provide a sense of the 
technology categories listed above. The process technology summaries 
are based on information provided by the respective companies. EPA has 
not been able to confirm all of the information, statements, process 
conditions, and the process flow steps necessary for any of these 
processes and companies.
1. Biochemical
    Biochemical conversion refers to a broad grouping of processes that 
use

[[Page 42253]]

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.
[GRAPHIC] [TIFF OMITTED] TP20JY10.002

    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.
---------------------------------------------------------------------------

    \19\ Image From: http://www.afdc.energy.gov/afdc/ethanol/
production_cellulosic.html.
---------------------------------------------------------------------------

    The following sections will discuss each of these steps in greater 
detail, discuss some of the variations to this general process, and 
discuss some of the advantages and disadvantages of the biochemical 
process of producing biofuel from cellulosic materials as compared to 
other fuel production processes.
    Seven of the eight companies that EPA believes may produce 
cellulosic biofuel in 2011 plan to use a biochemical process to produce 
biofuels. Five of these companies, AE Biofuels, Dupont Danisco 
Cellulosic Ethanol, Fiberight, Iogen, and KL energy, all plan to use an 
enzymatic hydrolysis, while Agresti Biofuels and Bell Bio-Energy are 
pursuing gravity pressure vessel and single step process technologies, 
respectively. The main reason for the dominance of biochemical 
technologies in 2011 is the relatively low capital costs of these 
projects compared to other cellulosic biofuel facilities. Biochemical 
projects also benefit less from economies of scale, making smaller and 
less capital intensive commercial facilities more feasible. The 
following sections, as well as a technical memorandum that has been 
added to the docket \20\, provide more information on the biochemical 
processes being pursued by majority of the companies we expect to 
produce cellulosic biofuels and make them commercially available in 
2011, as well as many other companies planning to begin production in 
later years.
---------------------------------------------------------------------------

    \20\ Wyborny, Lester. ``In-Depth Assessment of Advanced Biofuels 
Technologies.'' Memo to the docket, May 2010.
---------------------------------------------------------------------------

a. Feedstock Handling
    The first step of the biochemical conversion process is to insure 
that the biomass stream can be utilized by the rest of the conversion 
process. This most often takes the form of size reduction, either by 
grinding or chipping as appropriate for the type of biomass. While this 
is a relatively simple process it is essential to allow the following 
steps of the process to function as designed. It is also a potentially 
energy intensive process. It may be possible for biofuel producers to 
purchase cellulosic material that is already of the appropriate size, 
however we believe that in the near term this is unlikely and most 
biofuel producers will have to invest in equipment to reduce the size 
of the material they receive as needed for their process. In coming 
years, as the market for cellulosic materials expands, purchasing 
feedstock that has already been ground or chipped may be possible and 
cost effective, as these processes increase the density of this 
material and may reduce transportation costs.
    In addition to size reduction, steps must also be taken to remove 
any material from the feedstock that might be detrimental to the fuel 
production process. Contaminants in the feedstock, such as dirt, rocks, 
plastics, metals, and other non-biogenic materials, would at best 
travel through the fuel production process unchanged, resulting in 
reduced fuel production capacity. Depending on the type of contaminant 
they may also be converted to undesired byproducts that must be 
separated from the fuel. They could also be toxic to the biological 
organisms being used to convert the sugars to fuel, necessitating a 
shut down and restart of the plant. Any of these scenarios would result 
in a significant cost to the fuel producer. Feedstocks such as 
agricultural residues, wood chips, or herbaceous or woody energy crops 
are likely to contain far fewer contaminants than more heterogeneous 
feedstocks such as municipal solid waste (MSW).

[[Page 42254]]

b. Biomass Pretreatment
    The purpose of the biomass pretreatment stage is to disrupt the 
structure of the cellulosic biomass to allow for the hydrolysis of the 
cellulose and hemicellulose into simple sugars. The ideal pretreatment 
stage would allow for a high conversion of the cellulose and 
hemicellulose to simple sugars, minimize the degradation of these 
sugars to undesired forms that reduce fuel yields and inhibit 
fermentation, not require especially large or expensive reaction 
vessels, and be a relatively robust and simple process. No single 
biomass pretreatment method has yet been discovered that meets all of 
these goals, but rather a variety of options are being used by various 
cellulosic fuel producers, each with their own strengths and 
weaknesses. Dilute acid pretreatment and alkaline pretreatment are two 
methods currently being used that attack the hemicellulose and lignin 
portions of the cellulosic biomass respectively. Other methods, such as 
steam explosion and ammonia fiber expansion, seek to use high 
temperature and pressure, followed by rapid decompression to disrupt 
the structure of the cellulosic biomass and allow for a more efficient 
hydrolysis of the cellulose and hemicellulose to simple sugars. Each of 
these methods is discussed in more detail in a technical memo that has 
been added to the docket.\21\ The cost and characteristics of the 
cellulosic feedstock being processed is likely to have a significant 
impact on the pretreatment process that is used.
---------------------------------------------------------------------------

    \21\ Wyborny, Lester. ``In-Depth Assessment of Advanced Biofuels 
Technologies.'' Memo to the docket, May 2010.
---------------------------------------------------------------------------

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[deg] C. This treatment hydrolyzes the cellulose into glucose and 
other 6 carbon sugars that are then fed to biological organisms to 
produce the desired fuel. It is necessary to hydrolyze the 
hemicellulose and cellulose in two separate steps to prevent the 
conversion of the pentose sugars that result from the hydrolysis of the 
hemicellulose from being further converted into furfural and other 
chemicals. This would not only reduce the total production of sugars 
from the cellulosic feedstock, but also inhibit the production of fuel 
from the sugars in later stages of the process.
    The acidic solution containing the sugars produced as a result of 
the hydrolysis reaction must also be treated so that this stream can be 
fed to the biological organisms that will convert these sugars into 
fuel. In order to operate an acid hydrolysis process cost effectively 
the acid must be recovered, not simply neutralized. Methods currently 
being used to recover this acid include membrane separation and 
continuous ion exchange. The advantages of using an acid hydrolysis are 
that this process is well understood and capable of producing high 
sugar yields from a wide variety of feedstocks. Capital costs are high 
however, as materials compatible with the acidic streams must be 
extensively utilized. The high temperatures necessary for acid 
hydrolysis also result in considerable energy costs, and profitability 
is highly dependent on the ability to effectively recover and reuse the 
acid.
ii. Enzymatic Hydrolysis
    The enzymatic hydrolysis process uses enzymes, rather than acids, 
to hydrolyze the cellulose and any remaining hemicellulose from the 
pretreatment process. This process is much more versatile than the acid 
hydrolysis and can be used in combination with any of the pretreatment 
processes described above, provided that the structure of the 
lignocellulosic feedstock has been disrupted enough to allow the 
enzymes to easily access the hemicellulose and cellulose. After the 
feedstock has gone through pretreatment a cocktail of cellulose enzymes 
is added. These enzymes can be produced by the cellulosic biofuel 
producer or purchased from enzyme producers such as Novozymes, 
Genencor, and others. The exact mixture of enzymes used in the 
enzymatic hydrolysis stage can vary greatly depending on which of the 
pretreatment stages is used as well as the composition of the 
feedstock.
    The main advantages of the enzymatic hydrolysis process are a 
result of the mild operating conditions. Because no acid is used 
special materials are not required for the reaction vessels. Enzymatic 
hydrolysis is carried out at relatively low temperatures, usually 
around 50[deg] C, and atmospheric pressure and therefore has low energy 
requirements. These conditions also result in less undesired reactions 
that would reduce the production of sugars and potentially inhibit fuel 
production. Enzymatic hydrolysis works best with a uniform feedstock, 
such as agricultural residues or energy crops, where the concentration 
and combination of enzymes can be optimized for maximum sugar 
production. If the composition of the feedstock varies daily, as can be 
the case with fuel producers utilizing MSW or other waste streams, or 
even seasonally, it would make it more difficult to ensure that the 
correct enzyme cocktail is being used to carry out the hydrolysis as 
efficiently as possible. The main hurdle to using an enzymatic 
hydrolysis has been and continues to be the costs of the enzymes. 
Recent advances by companies that produce enzymes for the hydrolysis of 
cellulosic materials have resulted in a drastic cost reduction of these 
enzymes. If, as many researchers and cellulosic biofuel producers 
expect, the cost of these enzymes continues to fall it is likely that 
enzymatic hydrolysis will be a lower cost option than acid hydrolysis, 
especially for cellulosic biofuel producers utilizing uniform 
feedstocks.
d. Fuel Production
    After the cellulosic biomass has been hydrolyzed to simple sugars 
this sugar solution is converted to fuel by biological organisms. In 
some biochemical fuel production processes the sugars produced from the 
fermentation of the hemicellulose, which are mainly five carbon sugars, 
are

[[Page 42255]]

converted to fuel in a separate reactor and with a different set of 
organisms than the sugars produced from the cellulose hydrolysis, which 
are mainly six carbon sugars. Others processes, however, produce fuel 
from the five and six carbon sugars in the same reaction vessel.
    A wide range of biological organisms can be used to convert the 
simple sugars into fuel. These include yeasts, bacteria, and other 
microbes, some of which are naturally occurring and others that have 
been genetically modified. The ideal biological organism converts both 
five and six carbon sugars to fuel with a high efficiency, is able to 
tolerate a range of conditions, and is adaptable to process sugar 
streams of varying compositions that may result from variations in 
feedstock. Many cellulosic biofuel producers have their own proprietary 
organism or organisms optimized to produce the desired fuel from their 
unique combination of feedstock, pretreatment and hydrolysis processes, 
and fuel conversion conditions. Other cellulosic fuel producers license 
these organisms from biotechnology companies who specialize in their 
discovery and production.
    The many different biological organisms being considered for 
cellulosic biofuel production are capable of producing many different 
types of fuels. Many cellulosic biofuel producers are working with 
organisms that produce ethanol. In many ways this is the most simple 
fuel to produce from lignocellulosic biomass as the production of 
ethanol from simple sugars is a well understood process. Others intend 
to produce butanol or other alcohols that have higher energy content. 
Butanol may be able to be blended into gasoline in greater proportion 
to ethanol and therefore has a potentially greater market as well as 
value due to its higher energy content. Yields for butanol, however, 
are currently significantly lower per ton of feedstock than ethanol. 
Some of the fuel producers who plan to produce alcohols are considering 
purchasing and modifying already existing grain ethanol plants. This 
would potentially have significant capital cost savings as many of the 
units used in a grain ethanol process are very similar to those 
required by the biochemical fuel production process and could be used 
with minimal modification.
    Other cellulosic biofuel producers intend to produce hydrocarbon 
fuels very similar to gasoline, diesel, and jet fuel. These fuels 
command a higher price than alcohols, have a greater energy density, 
and are potentially drop in fuels that could be used in any 
conventional vehicles without strict blending limits. They could also 
be transported by existing pipelines and utilize the same 
infrastructure as the petroleum industry. Some of the processes being 
researched by fuel producers produce a single compound, such as iso-
octane, that would need to be blended into petroleum gasoline in order 
to be used while others produce a range of hydrocarbons very similar to 
those found in gasoline or diesel fuel refined from petroleum and could 
potentially be used in conventional vehicles without blending. While 
the prospect of producing hydrocarbon fuels from cellulosic feedstock 
is promising, the current yields of fuel produced by these organisms 
are significantly lower than those that are producing ethanol and other 
alcohols. Improvement in the yields of these organisms will have to be 
realized in order for cellulosic hydrocarbon fuels produced via a 
biochemical process to compete with cellulosic ethanol, and ultimately 
petroleum based fuels.
e. Fuel Separation
    In the fuel separation stage the fuel produced is separated from 
the water, lignin, any un-reacted hemicellulose and cellulose, and any 
other compounds remaining after the fuel production stage. The 
complexity of this stage is highly dependent on the type of fuel 
produced. For processes producing hydrocarbon fuels this stage can be 
as simple as a settling tank, where the hydrocarbons are allowed to 
float to the top and removed. Recovering the ethanol is a much more 
difficult task. To recover the ethanol a distillation process, nearly 
identical to that used in the grain ethanol industry, is used. The 
ethanol solution is first separated from the solids before being sent 
to a distillation column called a beer column. The overheads of the 
beer column are fed to a second distillation column, called a rectifier 
for further separation. The rectifier produces a stream with an ethanol 
of approximately 96%. A molecular sieve unit is then used to dehydrate 
this stream to produce fuel grade ethanol with purity greater than 
99.5%. Gasoline is added to the fuel ethanol as a denaturant before the 
fuel is stored. The distillation of ethanol is a very energy intensive 
process and new technologies, such as membrane separation, are being 
developed that could potentially reduce the energy intensity, and thus 
the cost, of the ethanol dehydration process. After the fuel has been 
recovered the remaining lignin and solids are dried and either burned 
on site to provide process heat and electricity or sold as a byproduct 
of the fuel production process. The waste water is either recycled or 
sent to a water treatment facility.
f. Process Variations
    While the process described above outlines the general biochemical 
process used by many cellulosic biofuel producers, there are several 
prominent variations being pursued by prospective biofuel producers. 
These variations usually seek to simplify the biochemical fuel 
production process by combining several steps into a single step or 
using other means to reduce the capital or operating costs of the 
process. Simultaneous Saccharification and Fermentation (SSF), 
Simultaneous Saccharification and Co-Fermentation (SSCF), Consolidated 
Bio-Processing (CBP), and Single Step Fuel Production are all 
production methods being developed by various biofuel production 
companies to combine two or more of the steps outlined above. These 
process variations are discussed in more detail in a technical memo 
that can be found in the docket.\22\ These modifications are usually 
enabled by a proprietary technology or biological organism that makes 
these changes possible.
---------------------------------------------------------------------------

    \22\ Wyborny, Lester. ``In-Depth Assessment of Advanced Biofuels 
Technologies.'' Memo to the docket, May 2010.
---------------------------------------------------------------------------

g. Current Status of Biochemical Conversion Technology
    The biochemical cellulosic fuel production industry is currently 
transitioning from an industry consisting mostly of small scale 
research and optimization focused facilities to one capable of 
producing fuel at a commercial scale. Companies such as Iogen, DuPont 
Danisco Cellulosic Ethanol, and KL Energy are just beginning to market 
the fuel they are producing at their first small scale commercial fuel 
production facilities. By 2011 we expect several other cellulosic fuel 
production facilities using biochemical processes to come online, 
including the first commercial scale facilities of AE Advanced Fuels, 
Agresti Biofuels, Bell Bio-Energy, and Fiberight. Many other 
facilities, including some large scale facilities capable of producing 
tens of millions of gallons of fuel are planned to come online starting 
in 2012 and in the following years.
    There are many factors that are likely to continue to drive the 
expansion of the cellulosic biofuel industry. The high price of 
petroleum fuels and the mandates put into place by the RFS2

[[Page 42256]]

program have created a large demand for cellulosic biofuels. The 
biochemical production process also has several advantages over other 
methods of producing fuel from cellulosic feedstocks including 
relatively low capital costs, highly selective fuel production, 
flexibility in the type of fuel produced, and the promise of future 
production cost reductions.
    While the poor worldwide economy and tight credit markets has had a 
negative impact on the biofuel industry as a whole the cellulosic 
biofuel producers utilizing biochemical processes have not been as hard 
hit as many others in the industry. This is partially due to the 
relatively low capital costs of biochemical production plants as a 
result of the relative simplicity and mild operating conditions of 
these plants. Several companies have been able to purchase distressed 
grain ethanol plants and are in the process of modifying them to 
produce cellulosic ethanol, further reducing the capital costs of their 
initial facilities. Once biochemical fuel production facilities have 
been constructed another advantage they have over other fuel production 
processes is that their high selectivity in the fuels they produce. 
Unlike chemical catalysts, which often produce a range of products and 
byproducts, biological organisms often produce a single type of fuel, 
which leads to very high fuel production rates per unit sugar. Finally, 
there is a large potential to further decrease the production costs of 
cellulosic biofuels using the biochemical processes. Unlike other 
production methods such as gasification which are relatively mature 
technologies, biochemical production of fuels is a young technology. 
One of the major costs of the biochemical fuel production processes 
currently are the enzymes. Great strides have been made recently in 
reducing the cost of these enzymes, and as the price of enzymes 
continues to fall so will the operating costs of biochemical fuel 
production processes.
h. Major Hurdles to Commercialization
    Despite the many promising qualities of the biochemical fuel 
production process several significant hurdles remain. Improvements 
must be made to the pretreatment processes of the cellulosic materials 
to maximize the conversion of cellulose and hemicellulose to simple 
sugars and to minimize the production of other undesired compounds, 
especially those that may inhibit the fuel production process. The 
ability of the biological fuel production organisms to process a wide 
range of both five and six carbon sugars must also continue to be 
improved. Both these improvements will increase the fuel yield per ton 
of cellulosic feedstock, reducing the operating costs of the process. 
The cost of enzymes must continue to decrease to allow the fuel 
produced by biochemical processes to be cost competitive with petroleum 
and other cellulosic biofuels.
    Another significant hurdle that must be overcome is the profitable 
utilization of the lignin portion of the cellulosic feedstock. Unlike 
some of the other cellulosic biofuel production processes, the 
biochemical process does not convert the lignin to fuel. Cellulosic 
feedstock can contain up to 40% lignin, depending on the type of 
feedstock used, so the effective utilization of this lignin is an 
important piece of the profitability of the biochemical process. One 
option for the use of the lignin is to burn it to provide process heat 
and electricity, as well as excess electricity to the grid. While this 
would provide good value for the lignin, it would require fairly 
expensive boilers and turbines that increases the capital cost of the 
facility. If the lignin cannot be used as part of the fuel production 
process it may be able to be marketed as a solid fuel with high energy 
density and low carbon intensity.
2. Thermochemical
    Thermochemical conversion involves biomass being broken down into 
syngas using heat and upgraded to fuels using a combination of heat and 
pressure in the presence of catalysts.\23\ For generating the syngas, 
thermochemical processes partially oxidize biomass in the presence of a 
gasifying agent, usually air, oxygen, and/or steam. It is important to 
note that these processing steps are also applicable to other 
feedstocks (e.g., coal or natural gas); the only difference is that a 
renewable feedstock is used (i.e., biomass) to produce cellulosic 
biofuel. The cellulosic biofuel produced can be mixed alcohols, but 
optimizing the process to produce ethanol, or it could be diesel fuel 
and naphtha. A thermochemical unit can also complement a biochemical 
processing plant to enhance the economics of an integrated biorefinery 
by converting lignin-rich, non-fermentable material left over from 
high-starch or cellulosic feedstocks conversion.\24\ Compared to corn 
ethanol or biochemical cellulosic ethanol plants, the use of biomass 
gasification may allow for greater flexibility to utilize different 
biomass feedstocks at a specific plant. Mixed biomass feedstocks may be 
used, based on availability of long-term suppliers, seasonal 
availability, harvest cycle, and costs.
---------------------------------------------------------------------------

    \23\ U.S. DOE. Technologies: Processing and Conversion. Accessed 
at: http://www1.eere.energy.gov/biomass/processing_conversion.html 
on October 28, 2008.
    \24\ EERE, DOE, Thermochemical Conversion, & Biochemical 
Conversion, Biomass Program Thermochemical R&D. http://
www1.eere.energy.gov/biomass/thermochemical_conversion.html http://
www1.eere.energy.gov/biomass/biochemical_conversion.html.
---------------------------------------------------------------------------

    The general steps of the gasification thermochemical process 
include: feedstock handling, gasification, gas cleanup and 
conditioning, fuel synthesis, and separation. Refer to Figure IV.C.2-1 
for a schematic of the thermochemical cellulosic ethanol production 
process through gasification. For greater detail on the thermochemical 
mixed-alcohols route refer to NREL technical documentation.\25\
---------------------------------------------------------------------------

    \25\ Aden, Andy, Mixed Alcohols from Woody Biomass--2010, 2015, 
2022, National Renewable Energy Laboratory (NREL), September 23, 
2009.

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[[Page 42257]]

[GRAPHIC] [TIFF OMITTED] TP20JY10.003

    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.
[GRAPHIC] [TIFF OMITTED] TP20JY10.004


[[Page 42258]]


    The first step in a thermochemical plant is feedstock size 
reduction. The particle size requirement for a thermochemical process 
is around 10-mm to 100-mm in diameter.\26\ Once the feed is ground to 
the proper size, flue gases from the char combustor and tar reformer 
catalyst regenerator dry the feed from the as received moisture level 
of around 30% to 50% moisture to the level required by the gasifier.
---------------------------------------------------------------------------

    \26\ Lin Wei, Graduate Research Assistant, Lester O. Pordesimo, 
Assistant Professor Willam D. Batchelor, Professor, Department of 
Agricultural and Biological Engineering, Mississippi State 
University, MS 39762, USA, Ethanol Production from Wood: Comparison 
of Hydrolysis Fermentation and Gasification Biosynthesis, Paper 
Number: 076036, Written for presentation at the 2007 ASABE Annual 
International Meeting. Minneapolis Convention Center, Minneapolis, 
MN, 17-20 June 2007.
---------------------------------------------------------------------------

    The dried, ground feedstock is fed to a gasification reactor for 
producing syngas. There are two general classes of gasifiers, partial 
oxidation (POx) and indirect gasifiers. Partial oxidation gasifiers 
(directly-heated gasifiers) use the exothermic reaction between oxygen 
and organics to provide the heat necessary to devolatilize biomass and 
to convert residual carbon-rich chars. Indirect gasifiers use steam to 
accomplish gasification through heat transfer from a hot solid or 
through a heat transfer surface. Either the byproduct char and/or a 
portion of the product gas can be combusted with air (external to the 
gasifier itself) to provide the energy required for gasification. The 
raw syngas produced from either type of gasifier has a low to medium 
energy content which consists mainly of CO, H2, 
CO2, H2O, N2, and hydrocarbons.
    Once the biomass is gasified and converted to syngas, the syngas 
must be cleaned and conditioned, as minor components of tars, sulfur, 
nitrogen oxides, alkali metals, and particulates have the potential to 
negatively affect the syngas conversion steps. Therefore, unwanted 
impurities are removed in a gas cleanup step and the gas composition is 
further modified during gas conditioning. Because this step is a 
necessary part of the thermochemical process, thermochemical plants are 
good candidates for processing municipal solid waste (MSW) which may 
contain a significant amount of toxic material. Gas conditioning steps 
include sulfur polishing to remove trace levels of H2S and 
water-gas shift to adjust the final H2/CO ratio for 
optimized fuel synthesis.
    After cleanup and conditioning, the ``clean'' syngas is comprised 
of essentially CO and H2. The syngas is then converted into 
a liquid fuel by a catalytic process. The fuel producer has the choice 
of producing diesel fuel or alcohols from syngas by optimizing the type 
of catalyst used and the H2/CO ratio. Diesel fuel has 
historically been the primary focus of such processes by using a 
Fischer Tropsch reactor, as it produces a high quality distillate 
product. However, with a $1.01 per gallon cellulosic biofuel tax 
deduction which favors the less energy dense ethanol, it may be 
economically advantageous for fuel producers to convert syngas to 
ethanol instead of to diesel fuel.
    A carefully integrated conventional steam cycle produces process 
heat and electricity (excess electricity is exported). Pre-heaters, 
steam generators, and super-heaters generate steam that drives turbines 
on compressors and electrical generators. The heat balance around a 
thermochemical unit or thermochemical combined unit must be carefully 
designed and tuned in order to avoid unnecessary heat losses.\27\ These 
facilities greatly increase the thermal efficiency of these plants, but 
they add to the very high capital costs of these technologies.
---------------------------------------------------------------------------

    \27\ S. Phillips, A. Aden, J. Jechura, and D. Dayton, National 
Renewable Energy Laboratory, Golden, Colorado 80401-3393, T. 
Eggeman, Neoterics International, Inc., Thermochemical Ethanol via 
Indirect Gasification and Mixed Alcohol Synthesis of Lignocellulosic 
Biomass, Technical Report, NREL/TP-510-41168, April 2007.
---------------------------------------------------------------------------

a. Ethanol Based on a Thermochemical Platform
    Conceptual designs and techno-economic models have been developed 
for ethanol production via mixed alcohol synthesis using catalytic 
processes. The proposed mixed alcohol process produces a mixture of 
ethanol along with higher normal alcohols (e.g., n-propanol, n-butanol, 
and n-pentanol). The by-product higher normal alcohols have value as 
commodity chemicals and fuel additives.
    The liquid rundown from the low-pressure separator is dehydrated in 
vapor-phase molecular sieves, producing the dehydrated mixed alcohol 
feed into a methanol/ethanol overhead stream and a mixed, higher 
molecular weight alcohol bottom stream. The overhead stream is further 
separated into a methanol stream and an ethanol stream.
    Two companies which are pursuing ethanol based on a thermochemical 
route are Range Fuels and Enerkem. Range has operated a pilot plant for 
over 7 years using over 20 different nonfood feedstocks. Range broke 
ground building its first commercial plant late in late 2008 and is 
expected to be operational in 2010. This plant will be located in 
Soperton, Georgia and is partially funded from proceeds of a DOE grant. 
The plant will use wood, grasses, and corn stover as feedstocks. In its 
initial phase, the Range plant is expected to produce 4 million gallons 
per year of methanol. After the company is confident in its operations, 
Range will begin efforts to expand the plant and add additional 
reaction capacity to convert the methanol to ethanol.
    Enerkem is pursuing cellulosic ethanol production via the 
thermochemical route. The Canadian-based company was recently announced 
as a recipient of a $50 million grant from DOE to build a 10 MGY woody 
biomass-to-ethanol plant in Pontotoc, MS. The U.S. plant is not 
scheduled to come online until 2012, but Enerkem is currently building 
a 1.3 MGY demonstration plant in Westbury, Quebec. According to the 
company, plant construction in Westbury started in October 2007 and the 
facility is currently scheduled to come online around the middle of 
2010. While it's unclear at this time whether the cellulosic ethanol 
produced will be exported to the United States, Enerkem has expressed 
interest in selling its fuel commercially. If Enerkem does export some 
of its cellulosic biofuel to the U.S., it could help to enable refiners 
meet the 2011 cellulosic biofuel standard.
b. Diesel and Naphtha Production Based on a Thermochemical Platform
    The cleaned and water-shifted syngas is sent to the Fischer Tropsch 
(FT) reactor where the carbon monoxide and hydrogen are reacted over a 
FT catalyst. Current FT catalysts include iron-based catalysts, and 
cobalt-based catalysts. The FT reactor creates a syncrude, which is a 
variety of hydrocarbons that boil over a wide distillation range (a mix 
of heavy and light hydrocarbons) which are separated into various 
components based on their vapor pressure, mainly liquid petroleum gas 
(LPG), naphtha, distillate and wax fractions. The heavier compounds are 
hydrocracked to maximize the production of diesel fuel. Conversely, the 
naphtha material is very low in octane thus, it would either have to be 
upgraded, or blended down with high octane blendstocks (i.e., ethanol), 
or be upgraded to a higher octane blendstock to have much value for use 
in gasoline.
    Choren is an European company which is pursuing a thermochemical 
technology for producing diesel fuel and naphtha. The principal aspect 
of Choren's process is their patented three stage gasification reactor. 
The three-stage gasification reactor includes low temperature 
gasification, high

[[Page 42259]]

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/biomass-to-liquids 
(BTL) plant in the U.S. after their Freiberg/Saxony plant is 
operational in Germany.
    Baard Energy is a U.S. company which plans on utilizing a 
thermochemical technology for producing diesel fuel and naphtha. Baard, 
however, plans on primarily combusting coal and cofiring biomass with 
the coal. Cofiring the biomass with the coal will make their first 
plant more like the coal-to-liquids plants which are operating today, 
which may help to convince investors that this technology is already 
tested. Baard's coal and biomass-to-liquids plant is not expected to be 
operational until at least 2012.
    Probably the largest commercialization hurdle for the companies 
pursing the thermochemical route is the very high capital costs 
associated with these technologies. Because of the economic hardships 
associated with recent global recession, banks are less willing to make 
loans to fund new technologies which are likely to be considered 
riskier investments. The capital costs are very high because there are 
two significant reactors required for each plant--the gasification 
reactor and the syngas to fuel reactor. Additionally, the syngas must 
be cleaned to protect the catalysts used in the downstream syngas to 
fuel reactor which requires additional capital costs. Because the 
syngas would be cleaned anyways, this technology is a very good 
candidate for processing MSW which may contain toxic compounds. When 
considering the cost savings for not having to pay the tipping fees at 
municipal dumping grounds, MSW feedstocks may avoid almost all the 
purchase costs for MSW feedstocks which would significantly help offset 
the high capital costs.
3. Hybrid Thermochemical/Biochemical Processes
    Hybrid technologies include process elements involving both the 
gasification stage of a typical thermochemical process, as well as the 
fermentation stage of a typical biochemical process and therefore 
cannot be placed easily into either category. For more specific 
information regarding either biochemical processes or thermochemical, 
please see Sections IV.C.1 and IV.C.2 respectively. Currently, there 
are several strategies for the production of ethanol through hybrid 
processes; these strategies are differentiated by the order in which 
the thermochemical and biochemical steps take place within the process, 
as well as how the intermediate products from each step are used.
    While we do not expect significant commercial production from 
hybrid processes in 2011, there are several companies pursing this 
approach for the future. Examples of the first process strategy, 
described in the paragraph below, include both INEOS Bio and Coskata. 
INEOS Bio (along with partner New Planet Energy) has recently been 
selected for a $50MM DOE grant for the construction of an 8 MGPY plant 
in River County, Florida; predicted to finish construction in late 
2011. Coskata is currently running a 40,000 gallon per year pilot plant 
that became operational in 2009 in Madison, Pennsylvania. Coskata is 
targeting to design and build a 50 MGPY commercial plant that it 
expects to be operational in 2012. A company currently pursing the 
second process strategy, described in the following third paragraph, is 
Zeachem Inc. Zeachem is currently constructing a 250 KGPY demonstration 
plant in Boardman, Oregon. They have received a $25MM DOE grant and 
expect to have a full commercial production facility operational in 
2013.
    One strategy involves the gasification of all feedstock material to 
syngas before being processed into ethanol using a biochemical 
fermenter. Further information regarding gasification can also be found 
in Section IV.C.2. After gasification, the syngas stream is cooled and 
bubbled into a fermenter containing modified microorganisms, usually 
bacteria or yeast. This fermenter replaces the typical catalysts found 
after gasification in a traditional thermochemical process. Further 
information regarding fermentation can be found in Section IV.C.1. 
Unlike traditional fermentation (which break down C5 and C6 sugars), 
these microorganisms are engineered to convert the carbon monoxide and 
hydrogen contained in the syngas stream directly into ethanol. After 
fermentation, the effluent water/ethanol stream from the fermenter is 
separated similarly to a biochemical process; usually using a 
combination of distillation and molecular sieves. The separated water 
can then be recycled back into the fermentation stage of the process. 
Typical yields of ethanol are predicted in the 100-120 gallon per ton 
range.
    Since gasification converts all carbonaceous feedstock material to 
a uniform syngas before fermentation, there is a higher flexibility of 
feedstock choices than if these materials were to be fermented 
directly; including agricultural residues, switchgrass, farm-grown 
trees, sorted MSW, or any combination of such. In addition, processing 
incoming feedstock with gasification does not require the addition of 
enzymes or acid hydrolysis necessary in a biochemical process to aid in 
the breakdown of cellulosic materials. Fermenting syngas also captures 
all available carbon contained in the feedstock, including lignin that 
would not be processed in a typical biochemical fermentation. However, 
more energy is lost as waste heat as well as secondary carbon dioxide 
production in the gasification process than would be lost for 
biochemical feedstock preparation. Using a fermenter in a hybrid 
process replaces the catalyst needed in a typical thermochemical 
process. These microorganisms allow for a higher variation of the 
incoming syngas stream properties, avoid the necessity of a water-shift 
reaction preceding traditional catalytic conversion, and are able to 
operate at lower temperatures and pressures than those required for a 
catalytic conversion to ethanol. Microorganisms, unlike a catalyst, are 
also self-sustaining and do not require periodic replacement. They are, 
however, susceptible to bacterial and viral infections which requires 
periodic cleaning of the fermentation reactors.
    Another hybrid production strategy involves gasification of the 
typically unfermentable feedstock fraction (lignin) concurrently with a 
typical fermentation step for the cellulose and hemicellulose fraction. 
These steps are subsequently combined in a hydrogenation reaction of 
the produced syngas with the product of the fermented stream. Feedstock 
first undergoes acid hydrolysis to break down contained cellulose and 
hemicellulose. Before fermentation, the unfermentable portion of 
feedstock (lignin, ash and other residue) is fractioned and sent to a 
gasifier. Concurrently, the remaining fraction of hydrolyzed feedstock 
is fermented using an acetogen microorganism. These acetogens occur 
naturally, and therefore do not have to be modified for this

[[Page 42260]]

process. These acetogen convert both C6 and C5 portions of the 
hydrolized feedstock to acetic acid. This reaction creates no carbon 
dioxide, unlike traditional fermentation using yeast, preserving the 
maximum amount of carbon for the finished fuel. The acetic acid stream 
then undergoes esterification to create ethyl acetate. Meanwhile, the 
syngas stream from the gasification of lignin and other residue is 
separated into its carbon monoxide and hydrogen components. The carbon 
monoxide stream can be further combusted to provide process heat or 
energy. The hydrogen stream is combined with the ethyl acetate in a 
hydrolysis reaction to form ethanol. Acetic acid and ethyl acetate also 
form the precursors to many other chemical compounds and therefore may 
also be sold in addition to ethanol. Typical yields for this technology 
are predicted in the 130-150 gallon per ton range.
4. Pyrolysis and Depolymerization
    Pyrolysis and depolymerization is a group of technologies which are 
capable of creating biofuels from cellulose by either thermally or 
catalytically breaking them down into molecules which fall within the 
boiling range of transportation fuels. Pyrolysis technologies are 
usually thought of being primarily a thermal technology, however, newer 
pyrolysis technologies are being developed which are attempting to 
integrate some catalysts into the technology. These are all unique 
processes, typically with single companies developing the technologies, 
so they are discussed separately.
a. Pyrolysis Diesel Fuel and Gasoline
    Pyrolysis oils, or bio-oils, are produced by decomposing cellulosic 
biomass at lower temperatures than the gasification process, thus 
producing a liquid bio oil instead of a synthesis gas.\28\ The reaction 
can occur either with or without the use of catalysts, but it occurs 
without any additional oxygen being present. The resulting oil which is 
produced must have particulates and ash removed in filtration to create 
a homogenous ``dirty'' crude oil type of product. This dirty crude oil 
must be further upgraded to hydrocarbon fuels via hydrotreating and 
hydrocracking processing, which reduces its total oxygen content and 
cracks the heaviest of the hydrocarbon compounds. One of the finished 
fuels produced by the pyrolysis process is diesel fuel, however, a 
significant amount of gasoline would likely be produced as well. There 
are two main reaction pathways currently being explored: A two step 
pyrolysis pathway, and a one step pyrolysis pathway.
---------------------------------------------------------------------------

    \28\ DOE EERE Biomass Program. ``Thermochemical Conversion 
Processes: Pyrolysis'' http://www1.eere.energy.gov/biomass/
thermochemical_processes.html, November 6, 2008.
---------------------------------------------------------------------------

    The simplest technology used for the two-step pyrolysis approach is 
called fast pyrolysis. The fast pyrolysis technology uses sand in a 
fluidized bed to transform bio-fuels into a product named bio-oil. This 
is purely a thermal process, where the sand's (or other solid) role is 
to transport heat to the biomass. Fast pyrolysis technology has two 
problems to be solved. First, fast pyrolysis oil is unstable, acidic, 
viscous and may separate itself into two phases so it must be 
immediately upgraded or it will begin to degrade and repolymerize. The 
second issue is that pyrolysis bio-oil must be upgraded before it can 
be used as a transportation fuel.
    Another approach to Fast Pyrolysis being pursued by several 
companies would be to substitute a catalyst in place of sand and the 
catalyst would be able to stabilize the resulting bio-oil in addition 
to helping depolymerize the biomass to liquids. Although the resulting 
bio-oil is stable, it still has to be upgraded into a transportation 
fuel, since it would still have a high level of oxygenated compounds.
    The National Renewable Energy Laboratory (NREL) is working on a 
``hot filtration'' technology that apparently is able to stabilize bio-
oil created using the fast pyrolysis process for a very long period of 
time (years). This would allow the bio-oil to be stored and transported 
to an upgrading facility without significant degradation.
    It is possible to use a sophisticated catalyst (instead of sand) in 
a single step pyrolysis reaction to create pyrolysis oils that exhibit 
much improved bio-oil properties. The catalysts would not only be able 
to help depolymerize cellulosic feedstocks, but they produce a bio-oil 
which could possibly be used directly as transportation fuel. Thus, a 
second upgrading step may not be necessary. The difficulty encountered 
by this technology is that catalysts which have been used in the one 
step process are relatively expensive and they degrade quickly due to 
the metals which are present in the biomass. Development work on the 
two-step and one-step pyrolysis processes is ongoing.
    Dynamotive Energy Systems Corporation is a Canadian company which 
has developed a pyrolysis technology that uses medium temperatures and 
oxygen free reactions to convert dry waste biomass and energy crops 
into different products. The liquid product produced by the Dynamotive 
process is called BioOil. The BioOil contains up to 25% water, though 
the water is intimately mixed and does not easily separate into another 
phase with time. Since the BioOil contains significant amounts of 
water, it is not directly useable as fuel in conventional vehicles and 
would have to be converted via another catalytic conversion processing 
step. The additional catalytic step envisioned by Dynamotive to upgrade 
the BioOil into a transportation fuel would combust the material into a 
synthesis gas which would then be converted into diesel fuel or bio-
methanol via a catalytic reaction (the BTL process). The diesel fuel 
produced is expected to be compatible with existing petroleum diesel 
fuels. The poor quality BioOil, though, could be used in the No. 2 
industrial heating oil market at industrial facilities. However, 
because of its high acidity level, users would need to change equipment 
metallurgy to stainless steel for pipes, pumps, tanks, nozzles etc.
    Dynamotive has two small demonstration plants. One demonstration 
plant is located in Guelph, Ontario, Canada and its capacity is 66,000 
dry tons of biomass a year with an energy output equivalent to 130,000 
barrels of oil. The other of its demonstration plants is located in 
West Lorne Ontario, Canada. Dynamotive continues to work on a 
technology for converting its BioOil to transportation fuels, although 
they have not announced plans for building such a facility due to 
funding limits. While Dynamotive is expected to continue to sell its 
fuel into the chemicals market, it could find a fuel oil user in the 
U.S. to use its fuel under the RFS2 program that refiners could use to 
comply with the 2011 cellulosic biofuel standard.
    Envergent is a company formed through a joint venture between 
Honeywell's UOP and the Ensyn Corporation. Although Ensyn has been 
using fast pyrolysis for more than a decade to produce specialty 
chemicals, UOP is relying on its decades of experience developing 
refining technologies to convert the pyrolysis oils into transportation 
fuels. Envergent is also working with Federal laboratories to further 
their technology. Based on their current technology and depending on 
the feedstock processed, about 70% of the feedstock is converted into 
liquid products. The gasoline range products produced are high in 
octane, while the diesel fuel products are low in cetane. Envergen 
estimates that if it was able to procure cellulosic feedstocks at 70 
per ton, that their technology would be competitive with

[[Page 42261]]

2 fuel oil produced from crude oil priced at about $40 per 
barrel. Envergent is licensing this technology as well as working with 
a U.S. oil company to test out this technology in a commercial setting 
here in the U.S.
    Petrobras is a Brazilian oil company also working to develop a 
pyrolysis technology. Because of Petrobas' work in this area (and other 
areas on biofuels), a Memorandum of Understanding was signed by United 
States' Secretary of State and Brazil's External Relations Minister on 
March 9, 2007 to advance the cooperation on biofuels. A second 
Memorandum of Understanding was signed by PETROBRAS and NREL on 
September 2008 aiming at collaborating to maximize the benefit of their 
respective institutional interests in second generation biofuels. 
Petrobras is negotiating a Cooperation Agreement with NREL to develop a 
two step pyrolysis route to produce biofuels from agricultural wastes 
such as sugar cane bagasse, wood chips or corn stover. Petrobras is 
optimistic that a catalytic pyrolysis technology can be developed that 
will produce a stable bio-oil (pyrolysis oil). Petrobras is hopeful 
that a one-step pyrolysis technology can be developed to convert 
biomass directly to transportation fuels, although in the end Petrobras 
believes that the two step process may be more economically attractive.
b. Catalytic Depolymerization
    Two companies that are pursuing catalytic depolymerization are 
Green Power Inc. and Cello Energy.
    The Green Power process catalytically depolymerizes cellulosic 
feedstocks at moderate temperatures into liquid hydrocarbon fuels. The 
proposed feedstock is municipal solid waste (MSW) or other waste 
material such as animal waste, plastics, agriculture residue, woody 
biomass and sewage waste. The feedstock is first ground to a size finer 
than 5 mm. The feedstock is placed along with a catalyst, some lime, 
which serves as a neutralizing agent, and some fuel which provides a 
liquid medium, into a reactor and heated to around 350 degrees Celsius. 
As described, this technology may fit the description for catalyzed 
pyrolysis reactions described above, but because we are not certain of 
the reaction kinetics, we have categorized this as a separate catalytic 
depolymerization technology. In the reactor, the feedstock is 
catalytically converted to liquid fuels which primarily fall within the 
gasoline and diesel fuel boiling ranges, although these fuels may need 
further upgrading. The liquid fuels are separated from some solids 
which are present and are distilled into typical fuel streams including 
naphtha, diesel fuel, kerosene and fuel oil. According to the 
literature writing about this technology, the process reportedly 
produces 120 gallons per ton of feedstock inputted into the process. A 
light hydrocarbon gas, which is mostly methane, is also produced, but 
this gas is expected to be burned in a turbine to generate electricity 
and the waste heat is used for heating the process. Apparently, some 
carbon dioxide is also formed and is released from the process.
    Greenpower completed construction on a demonstration plant located 
in Fife, Washington about March of 2008. Greenpower is working on 
obtaining additional funding and to obtain an air permit through the 
State of Washington Environmental Office. While we don't believe that 
Greenpower will have its plant operational in 2011 due to financial and 
other issues the company faces, those issues could be resolved to allow 
this company to produce fuel that could help refiners comply with the 
cellulosic biofuel volume standard for 2011.
    The Cello-Energy process is also a catalytic depolymerization 
technology. At moderate pressure and temperature, the Cello-Energy 
process catalytically removes the oxygen and minerals from the 
hydrocarbons that comprise finely ground cellulose. This results in a 
mixture of short chain (3, 6 and 9 carbon) hydrocarbon compounds. These 
short chain hydrocarbon compounds are polymerized to form compounds 
that boil in the diesel boiling range, though the process can also be 
adjusted to produce gasoline or jet fuel. The resulting diesel fuel 
meets the ASTM standards, is in the range of 50 cetane to 55 cetane and 
typically contains 3 ppm of sulfur.
    The Cello process is reported to be on the order of 82% efficient 
at converting the feedstock energy content into the energy content of 
the product, which is very high compared to most of today's biochemical 
and thermochemical processes which are on the order of 50% efficient, 
or less. Because of the simplicity of the process, the capital costs 
are very low. A 50 million gallon per year plant is claimed to only 
incur a total cost of $45 million. Because of its high efficiency in 
converting feedstocks into liquid fuel, the production and operating 
costs are estimated to be very low.
    In December 2008, Cello completed construction on a 20 million 
gallon per year commercial demonstration plant. However, at the present 
they are still working to resolve process issues that have arisen upon 
scaleup from their pilot plant. We expect that Cello will be able to 
produce some volume of cellulosic biofuel in 2011.
5. Catalytic Reforming of Sugars to Gasoline
    Virent Biorefining is pursuing a process called ``Bioforming'' 
which functions similarly as the gasoline reforming process used in the 
refining industry. Hence, this is a very different technology to any of 
those other cellulosic biofuel technologies discussed above. While 
refinery-based catalytic reforming technologies raise natural 
gasoline's octane value and produces aromatic compounds, Bioforming 
reforms biomass-derived sugars into hydrocarbons for blending into 
gasoline and diesel fuel. The process operates at moderate temperatures 
and pressures. In March of 2010, Virent announced that they had begun 
operating a larger pilot plant capable of about 30 gallons per day. 
Commercialization of the Virent process will happen sometime after 
2011.
    For this technology to become a cellulosic biofuel technology, it 
will be necessary to link this reforming technology with a technology 
which breaks cellulose down into starch or sugars. In parallel with its 
Bioreforming work, Virent is working on a technology to break down 
cellulose into sugars upstream of its technology which reforms sugars 
to gasoline.

V. Proposed Changes to RFS2 Regulations

    Following publication of the final RFS2 program regulations ,\29\ 
EPA identified two program areas that could benefit from the addition 
of new regulatory provisions. The first would provide for the 
generation of RINs for fuel produced between July 1, 2010 and December 
31, 2010 representing certain fuel pathways that are not currently in 
Table 1 to Sec.  80.1426, but which could possibly be added later this 
year if they are determined to meet the applicable GHG thresholds. 
Under this proposal RINs could be generated only if the pathways are 
indeed approved, and only for quantities reflecting fuel produced 
between the effective date of the RFS2 regulations and the effective 
date of a new pathway added to Table 1 to Sec.  80.1426. The second 
program addition would establish procedures for petitions requesting 
EPA authorization of an aggregate compliance approach to renewable 
biomass verification for feedstocks grown in foreign countries, akin to 
that applicable to crops and crop

[[Page 42262]]

residue grown within the U.S. We are proposing to make amendments to 
the RFS regulations in Subpart M to implement both of these provisions.
---------------------------------------------------------------------------

    \29\ 75 FR 14670, March 26, 2010.
---------------------------------------------------------------------------

A. Delayed RIN Generation for New Pathways

    As described in the RFS2 final rule, we did not have sufficient 
time to complete the necessary lifecycle GHG impact assessment for 
certain fuel pathways. We indicated that we would model and evaluate 
several additional pathways after the final rule (see Section V.C of 
the RFS2 final rule, 75 FR 14796). EPA anticipates modeling and 
publishing the lifecycle GHG analyses for the following four pathways 
later this year:
     Grain sorghum ethanol.
     Pulpwood biofuel.
     Palm oil biodiesel.
     Canola oil biodiesel.
Depending on how these lifecycle GHG results compare with the required 
GHG thresholds for cellulosic biofuel, biomass-based diesel, advanced 
biofuel, and conventional renewable fuel, we may add one or more of 
these pathways to Table 1 to Sec.  80.1426. Once a new pathway is 
approved, producers using that pathway could generate RINs with the 
specified D code.
    We consider the four new fuel pathways currently being analyzed to 
be an extension of the RFS2 final rule. Had we been able to complete 
these analyses for the RFS2 final rule and verified that the GHG 
thresholds had been met, D codes to represent these pathways would have 
been included in Table 1 to Sec.  80.1426 promulgated on March 26, 
2010, and renewable fuel producers could have begun using those 
pathways to generate RINs beginning on July 1, 2010. Indeed, we are 
aware of a number of producers who intend to produce biofuel using one 
of the four pathways listed above despite the fact that a determination 
regarding their lifecycle GHG impact has not yet been made.
    Based on the fact that we may have included the four pathways 
listed above in the RFS2 final rule if the lifecycle modeling had been 
completed in time, we believe that it would be appropriate to allow 
renewable fuel producers using any of these four pathways that are 
ultimately approved for inclusion in Table 1 to Sec.  80.1426 to 
generate RINs for all fuel they produce and sell on and after July 1, 
2010. However, while EPA is expeditiously working to complete its GHG 
assessments for these four fuel pathways in 2010, the determination of 
whether any of the four pathways will meet the 20%, 50%, or 60% GHG 
thresholds may not occur until after July 1, 2010. Therefore, RINs 
representing fuel produced between July 1, 2010 and any EPA approval of 
a new fuel pathway could only be generated after the renewable fuel in 
question had been produced and sold, after the time when EPA announces 
the results of the lifecycle analyses and specifies the applicable D 
code in Table 1 to Sec.  80.1426. Thus we are proposing a new 
regulatory provision for the generation of ``Delayed RINs'' that would 
allow RINs with newly specified D codes to be generated for eligible 
fuel produced between July 1, 2010 and the date any new D code is 
approved for one of the four fuel pathways listed above. This Delayed 
RINs provision would only be applicable for any of the four pathways 
described above that are determined to meet the applicable GHG 
thresholds. We are also proposing that this provision would apply only 
for renewable fuel produced in 2010, since the lifecycle GHG 
assessments for the four pathways listed above is expected to be 
completed in 2010. Our proposed regulatory provision for Delayed RIN 
generation would be inserted into Sec.  80.1426 as new paragraph (g). 
As for any RIN generation, producers using this new regulatory 
provision would need to be registered under RFS2 before they could 
generate Delayed RINs, and would need to comply with the recordkeeping 
and reporting requirements of the regulations.
    We do not believe that this proposed provision for Delayed RINs 
should be extended to any other pathways. The four pathways listed 
above are the only pathways currently under evaluation that would have 
been included in the RFS2 final rule if we had completed the modeling 
in time. Moreover, we have provided a petition process in Sec.  80.1416 
for other fuel pathways for which lifecycle GHG assessments have not 
yet been made.
    In developing this proposed provision for Delayed RIN Generation, 
we have accounted for renewable fuel producers who are eligible for an 
exemption from the 20% GHG reduction requirement for their fuel under 
Sec.  80.1403 (``grandfathered'' producers) and those that are not. 
Grandfathered producers can generate RINs for their renewable fuel 
starting on July 1, 2010, but must designate the D code as 6 for such 
fuel, identifying it as conventional renewable fuel. They must also 
transfer those RINs with renewable fuel they sell. If one of the four 
fuel pathways described above is approved between July 1, 2010 and 
December 31, 2010 for use of a D code other than 6, and the producer 
wishes to apply this new D code to fuel they have already produced and 
transferred, the RINs they already generated and transferred with 
renewable fuel they produced must be accounted for. We are proposing a 
process whereby these grandfathered producers would be required to 
acquire and retire RINs from the open market with a D code of 6 prior 
to the generation of Delayed RINs. The number of RINs retired in this 
fashion must be no greater than the number they generated between July 
1, 2010 and the effective date of the new applicable pathway. Producers 
who are not grandfathered under Sec.  80.1403 cannot generate RINs 
starting on July 1, 2010, and so would not be required to acquire and 
retire any RINs prior to the generation of Delayed RINs.
    The generation of Delayed RINs would also differ for grandfathered 
producers and non-grandfathered producers. Grandfathered producers 
would base the number of Delayed RINs they generate on the number of 
RINs with a D code of 6 that they retired as described above. In 
contrast, non-grandfathered producers would base the number of Delayed 
RINs they generate on the volume of renewable fuel they produced and 
sold between July 1, 2010 and the effective date of the new pathway. 
Since all Delayed RINs will be generated after the renewable fuel in 
question had been produced and sold, they would be assigned a K code of 
2 and thus could be sold by the producer separately from renewable 
fuel.
    Finally, we believe that there should be a deadline for the 
generation of Delayed RINs to ensure that they are entering the market 
as close as possible to the date of production of the renewable fuel 
that they represent. We are proposing that all Delayed RINs must be 
generated within 30 days of the effective date of a new pathway added 
to Table 1 to Sec.  80.1426 between July 1, 2010 and December 31, 2010. 
We believe that 30 days would provide sufficient time for producers who 
are grandfathered to first acquire and retire RINs from the open 
market, and would be sufficient to allow any producer to generate 
Delayed RINs according to the procedures in the regulations. However, 
we request comment on a longer period within which Delayed RINs must be 
generated.
    We request comment on our proposed provision for Delayed RINs.

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

    In the preamble to the final RFS2 regulations, EPA indicated that, 
while we did not have sufficient data at the time to make a finding 
that the aggregate compliance approach adopted for domestically-grown 
crops and crop

[[Page 42263]]

residues would be appropriate for foreign-grown feedstocks, we would 
consider applying the aggregate compliance approach for renewable 
biomass on a country by country basis if adequate land use data becomes 
available.
    Since promulgation of the final RFS2 regulations, we have received 
several inquiries regarding the process, criteria, and data needed for 
EPA to approve the aggregate compliance approach for planted crops and 
crop residue grown in areas outside the U.S. Thus, in today's rule, EPA 
is proposing a process by which entities may petition EPA for approval 
of the aggregate compliance approach for specified renewable fuel 
feedstocks either in a foreign country as a whole or in a specified 
geographical area within a country. The proposed regulations include a 
general criterion and a number of considerations that EPA will use in 
evaluating petitions. They also include a list of submissions that are 
required, absent an explanation by petitioner of why they should not be 
required for EPA to approve a petition. The proposed rule also includes 
a description of the proposed process by which EPA would make decisions 
concerning any petitions received.
1. Criterion and Considerations
    In developing these proposed regulations, EPA relied substantially 
on the approach we used to determine that an aggregate compliance 
approach was appropriate for planted crops and crop residue from U.S. 
agricultural land. The fundamental finding that would be required of 
EPA in approving a petition for application of the aggregate approach 
would be that an aggregate compliance approach will provide reasonable 
assurance that specified renewable fuel feedstocks from a given 
geographical area meet the definition of renewable biomass and will 
continue to meet the definition of renewable biomass, based on the 
submission of credible, reliable and verifiable data. Based on our 
experience in making the comparable finding for U.S.-grown crops and 
crop residues, we are also proposing a number of more specific factors 
that would be considered in determining whether this finding should be 
made, as described below. EPA is proposing to consider:
     Whether there has been a reasonable identification of the 
aggregate amount of agricultural land in the specified geographical 
area on December 19, 2007 that was available for the production of the 
specified feedstock(s) and that satisfy the definition of renewable 
biomass, taking into account the definitions of terms such as 
``cropland,'' ``pastureland,'' ``planted crop,'' and ``crop residue'' 
included in the final RFS2 regulations.
     Whether information from years preceding and following 
2007 shows that the identified aggregate amount of land in the specific 
geographical area, called the 2007 baseline area of land, is not likely 
to be exceeded in the future.
     Whether economic considerations, legal constraints, 
historical land use and agricultural practices and other factors show 
that it is likely that producers of the feedstock(s) will continue to 
use agricultural land within the baseline area of land identified into 
the future, as opposed to clearing and cultivating land not eligible 
under the 2007 baseline.
     Whether there is a reliable method to evaluate on a 
continuing basis whether the 2007 baseline area of land is being or has 
been exceeded.
     Whether an entity has been identified to conduct data 
gathering and analysis needed for an annual EPA evaluation of the 
aggregate compliance approach if EPA grants the petition.
    EPA is requesting comments on the proposed general criterion and 
specific considerations for approving the aggregate compliance approach 
for non-domestically grown feedstocks. The existing approved aggregate 
approach for U.S. domestic feedstocks applies to all crops and crop 
residue that could be used in renewable fuel production. EPA has 
received inquiries on the extent to which approval could be obtained 
for a single, or limited number, of feedstocks. The proposed 
regulations leave open the possibility of feedstock-specific petitions, 
but EPA particularly solicits comment on the extent to which different 
or additional data submittals or inquiries would be appropriate for 
such petitions.
2. Data Sources
    To make the aggregate compliance determination for U.S. 
agricultural lands, EPA obtained USDA data from three independently 
gathered national land use data sources (the Farm Service Agency (FSA) 
Crop History Data, the USDA Census of Agriculture (2007), and the 
satellite-based USDA Crop Data Layer (CDL)). Please see Section 
II.C.4.c.iii. of the preamble to the final RFS2 rule (75 FR 14701 
(March 26, 2010)) for a more detailed description of the data sources 
used. Using these data sources, EPA was able assess the area of land 
(acreage) available in the United States under EISA for production of 
crops and crop residues that meet the definition of renewable biomass. 
In the case of a petition to apply the aggregate compliance approach to 
feedstocks from a specific geographical area in a foreign country, when 
considering the information and data submitted by the petitioner, EPA 
will evaluate such information on a case-by-case basis, but suggests 
that petitioners obtain data from sources that are at least as 
credible, reliable, and verifiable as the USDA data used to make the 
determination for U.S. agricultural land.
    When evaluating whether the data relied on are credible, reliable, 
and verifiable, EPA will take into account whether the data is 
submitted by, generated by, or approved by the national government of 
the foreign country in question, as well as how comprehensive and 
accurate the data source is. It is important for the national 
government of the area seeking consideration be involved in this 
process, and we seek comment on whether or not involvement of the 
national government should be required as part of the petitioning and/
or data submittal processes. Additionally, EPA will take into 
consideration whether the data is publically available, whether the 
data collection and analysis methodologies and information on the 
primary data source are available to EPA, and whether the data has been 
generated, analyzed, and/or approved or endorsed by an independent 
third party. EPA would also take into account the quality of the data 
that is available on an annual basis for EPA's annual assessments of 
any approved aggregate compliance approach, as well as whether the 
petitioner has identified an entity who will provide to EPA an analysis 
of the data updates each year following EPA's approval of the aggregate 
compliance approach for that area. Furthermore, EPA will consider 
agricultural land use trends from several years preceding 2007, as well 
as the years following 2007 to the time the petition is submitted in 
order to evaluate whether or not it is likely that a 2007 baseline 
would be exceeded in the future. EPA will consider whether there are 
laws in place in the area for which the petition was submitted that 
might prohibit or incentivize the clearing of new agricultural lands 
and the efficacy of these laws. EPA will also assess whether any market 
factors are expected to drive an increase in the demand for 
agricultural land.
3. Petition Submission
    EPA is proposing that all submittals, including the petition, 
supporting documentation, and annual data and analyses, be submitted in 
English. We are also proposing that petitioners submit specified 
information as part of their formal petition submission package, or 
explain why such

[[Page 42264]]

information is not necessary for EPA to approve their petition. 
Petitioners would need to submit an assessment of the total amount of 
land that is cropland or pastureland that was cleared or cultivated 
prior to December 19, 2007 and that was actively managed or fallow and 
nonforested on that date. For example, in assessing the amount of total 
existing agricultural land in the U.S. on the enactment date of EISA, 
EPA used FSA Crop History data to show that there were 402 million 
acres of agricultural land existing in the U.S. in 2007. Additionally, 
if the petitioner is seeking approval of the aggregate compliance 
approach for a particular feedstock, they would also need to submit an 
assessment of the total amount of agricultural land dedicated to that 
feedstock in 2007 within the specified area. Petitioners would also be 
required to provide EPA with maps or electronic data identifying the 
boundaries of the land in question and a description of the 
feedstock(s) for which the petitioner is submitting the petition.
    As part of the petition, the petitioner would be required to submit 
to EPA land use data that demonstrates that the land in question is 
agricultural land that was cleared or cultivated prior to December 19, 
2007 and that was actively managed or fallow and nonforested on that 
date, which may include satellite imagery data, aerial photography, 
census data, agricultural surveys, and/or agricultural economic 
modeling data. As mentioned above, the FSA crop history data used for 
the U.S. aggregate compliance approach determination consists of annual 
records of farm-level land use data that includes all cropland and 
pastureland in the U.S. EPA also considered USDA Census of Agriculture 
data, which consists of a full census of the U.S. agricultural sector 
once every five years, as well as the USDA Nation Agricultural 
Statistics Service (NASS) Crop Data Layer (CDL), which is based on 
satellite data.
    In establishing the total amount of existing agricultural land for 
the U.S. aggregate compliance approach determination, EPA relied on the 
RFS2 definitions of the relevant terms, including planted crops, crop 
residue, and agricultural land, which is defined as consisting of 
cropland, pastureland and CRP land. EPA will take into consideration 
whether the data submitted by the petitioner relies on comparable 
definitions. For purposes of RFS2, planted crops are defined as all 
annual or perennial agricultural crops from existing agricultural land 
that may be used as feedstocks for renewable fuel, such as grains, 
oilseeds, sugarcane, switchgrass, prairie grass, duckweed, and other 
species (but not including algae species or planted trees), providing 
they were intentionally applied by humans to the ground, a growth 
medium, a pond or tank, either by direct application as seed or plant, 
or through intentional natural seeding or vegetative propagation by 
mature plants introduced or left undisturbed for that purpose. Crop 
residue is defined as the biomass left over from the harvesting or 
processing of planted crops from existing agricultural land and any 
biomass removed from existing agricultural land that facilitates crop 
management (including biomass removed from such lands in relation to 
invasive species control or fire management), whether or not the 
biomass includes any portion of a crop or crop plant. Cropland is 
defined as land used for production of crops for harvest and includes 
cultivated cropland, such as for row crops or close-grown crops, and 
non-cultivated cropland, such as for horticultural or aquatic crops. 
Pastureland is land managed for the production of indigenous or 
introduced forage plants for livestock grazing or hay production, and 
to prevent succession to other plant types. It is important to note 
that EPA considers pastureland to be distinctly different from 
rangeland, which may be used for livestock grazing, but is not managed 
to prevent succession to other plant types. Finally, CRP land is land 
enrolled in the US Conservation Reserve Program (administered by USDA's 
Farm Service Agency), which encourages farmers to convert highly 
erodible cropland or other environmentally sensitive acreage to 
vegetative cover, such as tame or native grasses, wildlife plantings, 
trees, filterstrips, or riparian buffers. EPA recognizes that the CRP 
is only applicable to U.S. agricultural land. EPA solicits comments on 
whether the final rules should allow EPA to consider land that is 
equivalent or similar to US CRP land as existing agricultural land for 
purposes of RFS2-compliant feedstock cultivation in a foreign country, 
and whether EPA should be able to make such a determination in the 
context of a petition for application of the aggregate approach to a 
foreign country.
    The petitioner would also be required to provide EPA with 
historical land use data for the land in question, covering the years 
from prior to 2007 to the current year. For the U.S. aggregate 
compliance approach determination, EPA analyzed the FSA Crop History 
data from the years 2005 through 2007 and the USDA Census of 
Agriculture from 1997 through 2007, finding that there was an overall 
decade trend of contraction of agricultural land utilization in the 
U.S. The petitioner would need to provide a description of any 
applicable laws, agricultural practices, economic considerations, or 
other relevant factors that had or may have an effect on the use of the 
land in question. For the U.S. aggregate compliance approach 
determination, EPA also took in account the EISA renewable fuel 
obligations, the unsuitability and high cost of developing previously 
undeveloped land for agricultural purposes, as well as projected 
increases in crop yields on existing agricultural land.
    Finally, the petitioner would be required to provide EPA with a 
plan describing how the entity who will, on a continuing yearly basis, 
conduct any data gathering and analysis necessary to assist EPA in its 
annual assessment of any approved aggregate approach. In the plan, the 
petitioner would describe the data, the data source, and the schedule 
on which the data would be updated and made available to EPA and the 
public. Additionally, the plan would include the entity's strategy and 
schedule for conducting an annual analysis of the data and providing it 
to EPA.
4. Petition Process
    We believe that it will be important to incorporate a public 
comment component into EPA's deliberations on a petition made to 
incorporate an aggregate compliance approach for a new area. EPA plans 
to publish a Federal Register notice informing the public of incoming 
petitions, with information on how to view the petitions and any 
supporting information. EPA proposes to then accept public comment on 
the petition for a specified period of time. Once the public comment 
period closes, EPA will make an assessment, taking into account the 
information submitted in the petition as well as the comments received, 
and will then publish a decision in the Federal Register to either 
approve or deny the petitioner's request. If the petition has been 
approved, the Federal Register notice will specify an effective date at 
which time producers using the specified feedstocks from the specified 
areas identified in EPA's approval will be subject to the aggregate 
compliance approach requirements in 40 CFR 80.1454(g) in lieu of the 
renewable biomass recordkeeping and reporting requirements. In the 
event that the annual data submitted by the petitioner

[[Page 42265]]

is insufficient to demonstrate that the baseline amount of land has not 
been exceeded or if the annual data is not submitted in a timely 
manner, EPA will make a finding that the baseline acreage has been 
exceeded and producers using crops or crop residue from the specified 
area will be subject to the individual recordkeeping and reporting 
requirements described in the regulations. EPA is seeking comments on 
this proposed process. Additionally, EPA requests comment on whether 
the burden associated with the petition process is reasonable, and how 
it might be minimized while still remaining adequately robust. Specific 
estimates about the time and cost of preparing a petition will be 
published in Information Collection Request associated with this 
proposed rulemaking.

VI. Public Participation

    We request comment on all aspects of this proposal. This section 
describes how you can participate in this process.

A. How do I submit comments?

    We are opening a formal comment period by publishing this document. 
We will accept comments during the period indicated under DATES in the 
first part of this proposal. If you have an interest in the proposed 
standards and changes to the RFS regulations described in this 
document, we encourage you to comment on any aspect of this rulemaking. 
We also request comment on specific topics identified throughout this 
proposal.
    Your comments will be most useful if you include appropriate and 
detailed supporting rationale, data, and analysis. Commenters are 
especially encouraged to provide specific suggestions for any changes 
that they believe need to be made. You should send all comments, except 
those containing proprietary information, to our Air Docket (see 
ADDRESSES in the first part of this proposal) before the end of the 
comment period.
    You may submit comments electronically, by mail, or through hand 
delivery/courier. To ensure proper receipt by EPA, identify the 
appropriate docket identification number in the subject line on the 
first page of your comment. Please ensure that your comments are 
submitted within the specified comment period. Comments received after 
the close of the comment period will be marked ``late.'' EPA is not 
required to consider these late comments. If you wish to submit 
Confidential Business Information (CBI) or information that is 
otherwise protected by statute, please follow the instructions in 
Section VI.B.

B. How should I submit CBI to the agency?

    Do not submit information that you consider to be CBI 
electronically through the electronic public docket, http://
www.regulations.gov, or by e-mail. Send or deliver information 
identified as CBI only to the following address: U.S. Environmental 
Protection Agency, Assessment and Standards Division, 2000 Traverwood 
Drive, Ann Arbor, MI 48105, Attention Docket ID EPA-HQ-OAR-2010-0133. 
You may claim information that you submit to EPA as CBI by marking any 
part or all of that information as CBI (if you submit CBI on disk or 
CD-ROM, mark the outside of the disk or CD-ROM as CBI and then identify 
electronically within the disk or CD-ROM the specific information that 
is CBI). Information so marked will not be disclosed except in 
accordance with procedures set forth in 40 CFR part 2.
    In addition to one complete version of the comments that include 
any information claimed as CBI, a copy of the comments that does not 
contain the information claimed as CBI must be submitted for inclusion 
in the public docket. If you submit the copy that does not contain CBI 
on disk or CD-ROM, mark the outside of the disk or CD-ROM clearly that 
it does not contain CBI. Information not marked as CBI will be included 
in the public docket without prior notice. If you have any questions 
about CBI or the procedures for claiming CBI, please consult the person 
identified in the FOR FURTHER INFORMATION CONTACT section.

VII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993), 
this action is a ``significant regulatory action'' because it raises 
novel legal or policy issues. Accordingly, EPA submitted this action to 
the Office of Management and Budget (OMB) for review under EO 12866 and 
any changes made in response to OMB recommendations have been 
documented in the docket for this action.
    The economic impacts of the RFS2 program on regulated parties, 
including the impacts of the required volumes of renewable fuel, were 
already addressed in the RFS2 final rule promulgated on March 26, 2010 
(75 FR 14670). This action proposes the percentage standards applicable 
in 2011 based on the volumes that were analyzed in the RFS2 final rule. 
This action also proposes two new regulatory provisions that have been 
determined to have no adverse economic impact on regulated parties 
since they would increase flexibility to produce qualifying renewable 
fuel under the RFS2 program.

B. Paperwork Reduction Act

    The information collection requirements in this proposed rule have 
been submitted for approval to the Office of Management and Budget 
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The 
Information Collection Request (ICR) document prepared by EPA has been 
assigned EPA ICR number 2398.01.
    This proposed regulation has a provision that EPA would use to 
authorize renewable fuel producers using foreign-grown feedstocks to 
use an aggregate approach to comply with the renewable biomass 
verification provisions, similar to that applicable to producers using 
crops and crop residue grown in the United States. See discussion in 
Section V.B. For this authorization, foreign based entities could 
petition EPA for approval of the aggregate compliance approach for 
specified renewable fuel feedstocks either in a foreign country as a 
whole or in a specified geographical area within a country. This 
petition request for crops from foreign grown land areas would be 
voluntary. If approved by EPA, such a petition would allow biomass 
produced in a foreign country or geographical area to be counted as 
feedstock to make renewable fuel under the RFS2 program. Other actions 
in this proposed regulation would not impose any new information 
collection burdens on regulated entities beyond those already required 
under RFS2. The submission of this information is required in order for 
EPA to evaluate and act on the petitions. Respondents may assert claims 
of business confidentiality (CBI) for any or all of the information 
they submit. We do not believe that most respondents would characterize 
the information they submit to us under this information collection as 
CBI. However, any information claimed as confidential would be treated 
in accordance with 40 CFR Part 2 and established Agency procedures. 
Information that is received without a claim of confidentiality may be 
made available to the public without further notice to the submitter 
under 40 CFR 2.203.
    EPA estimates that there would be 15 respondents (petitioners), 
submitting 15 responses (petitions) in response to this provision. The 
estimated burden annual

[[Page 42266]]

burden, assuming 15 respondents, would be 200 hours and annual cost is 
$14,196. Burden is defined at 5 CFR 1320.3(b).
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for EPA's 
regulations in 40 CFR are listed in 40 CFR part 9.
    To comment on the Agency's need for this information, the accuracy 
of the provided burden estimates, and any suggested methods for 
minimizing respondent burden, EPA has established a public docket for 
this rule, which includes this ICR, under Docket ID number EPA-HQ-OAR-
2010-0133. Submit any comments related to the ICR to EPA and OMB. See 
ADDRESSES section at the beginning of this notice for where to submit 
comments to EPA. Send comments to OMB at the Office of Information and 
Regulatory Affairs, Office of Management and Budget, 725 17th Street, 
NW., Washington, DC 20503, Attention: Desk Office for EPA. Since OMB is 
required to make a decision concerning the ICR between 30 and 60 days 
after July 20, 2010, a comment to OMB is best assured of having its 
full effect if OMB receives it by August 19, 2010. The final rule will 
respond to any OMB or public comments on the information collection 
requirements contained in this proposal.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements under the Administrative 
Procedure Act or any other statute unless the agency certifies that the 
rule will not have a significant economic impact on a substantial 
number of small entities. Small entities include small businesses, 
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of today's rule on small 
entities, small entity is defined as: (1) A small business as defined 
by the Small Business Administration's (SBA) regulations at 13 CFR 
121.201; (2) a small governmental jurisdiction that is a government of 
a city, county, town, school district or special district with a 
population of less than 50,000; and (3) a small organization that is 
any not-for-profit enterprise which is independently owned and operated 
and is not dominant in its field.
    After considering the economic impacts of today's proposed rule on 
small entities, we certify that this proposed action will not have a 
significant economic impact on a substantial number of small entities. 
This rule sets the annual standard for cellulosic biofuels, proposes a 
regulatory provision for the generation of Delayed RINs, and 
establishes criteria for foreign countries to adopt an aggregate 
approach of compliance with the renewable biomass provision similar to 
that used in the U.S. However, the impacts of the RFS2 program on small 
entities were already addressed in the RFS2 final rule promulgated on 
March 26, 2010 (75 FR 14670). Therefore, this proposed rule will not 
impose any additional requirements on small entities. We continue to be 
interested in the potential impacts of the proposed rule on small 
entities and welcome comments on issues related to such impacts.

D. Unfunded Mandates Reform Act

    This action contains no Federal mandates under the provisions of 
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 
1531-1538 for State, local, or tribal governments or the private 
sector. The action imposes no enforceable duty on any State, local or 
tribal governments or the private sector. Therefore, this action is not 
subject to the requirements of sections 202 or 205 of the UMRA.
    This action is also not subject to the requirements of section 203 
of UMRA because it contains no regulatory requirements that might 
significantly or uniquely affect small governments.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have 
substantial direct effects on the States, on the relationship between 
the national government and the States, or on the distribution of power 
and responsibilities among the various levels of government, as 
specified in Executive Order 13132. This proposed rule does not have 
federalism implications. It will not have substantial direct effects on 
the States, on the relationship between the national government and the 
States, or on the distribution of power and responsibilities among the 
various levels of government, as specified in Executive Order 13132. 
Thus, Executive Order 13132 does not apply to this rule.
    In the spirit of Executive Order 13132, and consistent with EPA 
policy to promote communications between EPA and State and local 
governments, EPA specifically solicits comment on this proposed rule 
from State and local officials.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    This action does not have tribal implications, as specified in 
Executive Order 13175 (65 FR 67249, November 9, 2000). This proposed 
rule does not have tribal implications, as this rule will be 
implemented at the Federal level and impose compliance costs only on 
transportation fuel refiners, blenders, marketers, distributors, 
importers, and exporters. Tribal governments would be affected only to 
the extent they purchase and use regulated fuels. Thus, Executive Order 
13175 does not apply to this action.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying 
only to those regulatory actions that concern health or safety risks, 
such that the analysis required under section 5-501 of the EO has the 
potential to influence the regulation. This action is not subject to EO 
13045 because it does not establish an environmental standard intended 
to mitigate health or safety risks and because it implements specific 
standards established by Congress in statutes.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This rule is not a ``significant energy action'' as defined in 
Executive Order 13211, ``Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use'' (66 FR 28355 
(May 22, 2001)) because it is not likely to have a significant adverse 
effect on the supply, distribution, or use of energy.

I. National Technology Transfer Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (``NTTAA''), Public Law 104-113, 12(d) (15 U.S.C. 272 note) 
directs EPA to use voluntary consensus standards in its regulatory 
activities unless to do so would be inconsistent with applicable law or 
otherwise impractical. Voluntary consensus standards are technical 
standards (e.g., materials specifications, test methods, sampling 
procedures, and business practices) that are developed or adopted by 
voluntary consensus standards bodies. NTTAA directs EPA to provide 
Congress, through OMB, explanations when the Agency decides not to use 
available and applicable voluntary consensus standards.

[[Page 42267]]

    This proposed rulemaking does not involve technical standards. 
Therefore, EPA is not considering the use of any voluntary consensus 
standards.

J. Executive Order 12898: Federal Actions to Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes 
Federal executive policy on environmental justice. Its main provision 
directs Federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the United States.
    EPA has determined that this proposed rule will not have 
disproportionately high and adverse human health or environmental 
effects on minority or low-income populations because it does not 
affect the level of protection provided to human health or the 
environment. This action does not relax the control measures on sources 
regulated by the RFS2 regulations and therefore will not cause 
emissions increases from these sources.

VIII. Statutory Authority

    Statutory authority for this action comes from section 211 of the 
Clean Air Act, 42 U.S.C. 7545. Additional support for the procedural 
and compliance related aspects of today's proposal, including the 
proposed recordkeeping requirements, come from Sections 114, 208, and 
301(a) of the Clean Air Act, 42 U.S.C. Sections 7414, 7542, and 
7601(a).

List of Subjects in 40 CFR Part 80

    Environmental protection, Air pollution control, Diesel Fuel, Fuel 
additives, Gasoline, Imports, Labeling, Motor vehicle pollution, 
Penalties, Reporting and recordkeeping requirements.

    Dated: July 9, 2010.
Lisa P. Jackson,
Administrator.
    For the reasons set forth in the preamble, 40 CFR part 80 is 
proposed to be amended as follows:

PART 80--REGULATION OF FUELS AND FUEL ADDITIVES

    1. The authority citation for part 80 continues to read as follows:

    Authority: 42 U.S.C. 7414, 7542, 7545, and 7601(a).

    2. Section 80.1426 is amended by revising paragraph (e)(1) and 
adding paragraph (g) to read as follows:


Sec.  80.1426  How are RINs generated and assigned to batches of 
renewable fuel by renewable fuel producers or importers?

* * * * *
    (e) * * *
    (1) Except as provided in paragraph (g)(7) of this section for 
delayed RINs, the producer or importer of renewable fuel must assign 
all RINs generated to volumes of renewable fuel.
* * * * *
    (g) Delayed RIN generation. Parties who produce or import renewable 
fuel may generate delayed RINs to represent renewable fuel volumes that 
have already been transferred to another party if those renewable fuel 
volumes can be described by a pathway that has been added to Table 1 to 
Sec.  80.1426 on or after July 1, 2010 and before January 1, 2011.
    (1) When a new pathway is added to Table 1 to Sec.  80.1426, EPA 
will specify the effective date of that new pathway.
    (2) Delayed RINs must be generated within 30 days of the effective 
date of the rule in which the pathway is added.
    (3) Delayed RINs may only be generated to represent renewable fuel 
produced or imported between July 1, 2010 and the effective date of the 
rule in which the pathway is added.
    (4) If a party originally generated and transferred RINs with 
renewable fuel volumes, and those RINs can be described by a pathway 
added to Table 1 to Sec.  80.1426 on or after July 1, 2010 and before 
January 1, 2011, that party must retire a number of gallon-RINs prior 
to generating delayed RINs.
    (i) The number of gallon-RINs retired must not exceed the number of 
gallon-RINs originally generated to represent the renewable fuel 
volumes produced or imported between July 1, 2010 and the effective 
date of the rule in which the pathway is added.
    (ii) Retired RINs must have a D code of 6.
    (iii) Retired RINs must have a K code of 2.
    (iv) Retired RINs must have been generated in 2010.
    (5) For parties that retire RINs pursuant to paragraph (g)(4) of 
this section, the number of delayed gallon-RINs generated shall be 
equal to the number of gallon-RINs retired.
    (6) For parties that did not retire RINs pursuant to paragraph 
(g)(4) of this section, the number of delayed gallon-RINs generated 
shall be determined pursuant to paragraph (f) of this section.
    (i) The standardized volume of fuel (Vs) used to 
determine the RIN volume (VRIN) under paragraph (f) of this 
section shall be the standardized volume of renewable fuel produced or 
imported between July 1, 2010 and the effective date of the rule in 
which the pathway is added.
    (ii) The renewable fuel for which delayed RINs are generated must 
be described by a pathway that has been added to Table 1 to Sec.  
80.1426 on or after July 1, 2010 and before January 1, 2011.
    (7) All delayed RINs generated by a renewable fuel producer must be 
generated on the same date.
    (8) Delayed RINs shall have a K code of 2.
    (9) The D code that shall be used in delayed RINs generated shall 
be the D code specified in Table 1 to Sec.  80.1426 which corresponds 
to the pathway that describes the producer's operations.
    3. Section 80.1454 is amended by revising paragraph (g) 
introductory text to read as follows:


Sec.  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 Sec.  80.1401, or any producer or RIN-generating importer of 
renewable fuel made from feedstock covered by a petition approved 
pursuant to Sec.  80.1457, is subject to the aggregate compliance 
approach and is not required to maintain feedstock records unless EPA 
publishes a finding that the 2007 baseline amount of agricultural land 
has been exceeded or that the criterion in Sec.  80.1457(a) is no 
longer satisfied.
* * * * *
    4. Section 80.1457 is added to read as follows:


Sec.  80.1457  Petition process for international aggregate compliance 
approach.

    (a) EPA may approve a petition for application of the aggregate 
compliance approach to non-U.S. planted crops and crop residues from 
existing foreign agricultural land if it determines that an aggregate 
compliance approach will provide reasonable assurance that specified 
renewable fuel feedstocks from a given geographical area meet the 
definition of renewable biomass and will continue to meet the 
definition of renewable biomass, based on the submission of credible, 
reliable, and verifiable data.
    (1) As part of its evaluation, EPA will consider:
    (i) Whether there has been a reasonable identification of the

[[Page 42268]]

aggregate amount of agricultural land in the specified geographical 
area as of December 19, 2007 that was available for the production of 
the specified feedstock(s) and that satisfy the definition of renewable 
biomass;
    (ii) Whether information from years preceding and following 2007 
shows that the 2007 amount of agricultural land identified in paragraph 
(a)(1)(i) of this section is not likely to be exceeded in the future;
    (iii) Whether economic considerations, legal constraints, 
historical land use and agricultural practices, and/or other factors 
show that it is likely that producers of the feedstock(s) will continue 
to use agricultural land within area of land identified in paragraph 
(a)(1)(i) of this section in the future as opposed to clearing and 
cultivating land that was not included in that area of land.
    (iv) Whether there is a reliable method to evaluate on a continuing 
basis whether the 2007 area of land identified in paragraph (a)(1)(i) 
of this section is being exceeded; and
    (v) Whether an entity has been identified to conduct data gathering 
and analysis needed for the evaluation specified in paragraph 
(a)(1)(iv) of this section, for submission to EPA on an annual basis if 
EPA grants the petition.
    (2) [Reserved]
    (b) Any petition submitted under paragraph (a) of this section must 
be in the English language, and must include all of the following, or 
an explanation of why it is not needed for EPA to approve the petition:
    (1) Maps or electronic data identifying the boundaries of the land 
for which the petitioner seeks approval of an aggregate compliance 
approach.
    (2)(i) For petitions regarding crops or crop residue, the total 
amount of land that is cropland or pastureland within the geographic 
boundaries specified in paragraph (b)(1) of this section that was 
cleared or cultivated prior to December 19, 2007 and that was actively 
managed or fallow and nonforested on that date, and the total amount of 
land that is cropland or pastureland within the geographic boundaries 
specified in paragraph (b)(1) of this section that was not cleared or 
cultivated prior to December 19, 2007 and actively managed or fallow 
and nonforested on that date.
    (ii) If the petitioner is seeking approval of the aggregate 
compliance approach for a particular planted crop or crop residue, the 
total amount of land within the geographic boundaries specified in 
paragraph (b)(1) of this section that was used for the production of 
that feedstock in 2007 and that was actively managed or fallow and 
nonforested on that date, and the total amount of land within the 
geographic boundaries specified in paragraph (b)(1) of this section 
that was used for the production of that feedstock in 2007 that was not 
cleared or cultivated prior to December 19, 2007 and actively managed 
or fallow and nonforested on that date.
    (3) A description of the feedstock(s) for which the petitioner is 
submitting the petition.
    (4) Land use data that demonstrates that the land in question in 
paragraph (b)(1) of this section is cropland or pastureland that was 
cleared or cultivated prior to December 19, 2007 and that was actively 
managed or fallow and nonforested on that date, which may include any 
of the following:
    (i) Satellite imagery data.
    (ii) Aerial photography.
    (iii) Census data.
    (iv) Agricultural surveys.
    (v) Agricultural economic modeling data.
    (5) Historical land use data for the land within the geographic 
boundaries specified in paragraph (b)(1) of this section to the current 
year, which may include any of the following:
    (i) Satellite imagery data.
    (ii) Aerial photography.
    (iii) Census data.
    (iv) Agricultural surveys.
    (v) Agricultural economic modeling data.
    (6) A description of any applicable laws, agricultural practices, 
economic considerations, or other relevant factors that had or may have 
an effect on the use of the land within the geographic boundaries 
specified in paragraph (b)(1) of this section.
    (7) A plan describing how the petitioner will identify an entity 
who will, on a continuing basis, conduct data gathering, analysis, and 
submittal to assist EPA in making an annual determination of whether 
the criterion specified in paragraph (a) of this section remains 
satisfied.
    (8) Any additional information the Administrator may require.
    (c) If EPA approves a petition it will issue a Federal Register 
notice announcing its decision and specifying an effective date for the 
application of the aggregate compliance approach to the specified 
feedstock(s) from the specific geographical area. Thereafter, the 
specified feedstocks from the specified area will be covered by the 
aggregate compliance approach set forth in Sec.  80.1454(g), or as 
otherwise specified pursuant to paragraph (d) of this section.
    (d) If EPA grants a petition to establish an aggregate compliance 
approach for a specified feedstock(s) from a specific geographical 
area, it may include any conditions that EPA considers appropriate in 
light of the conditions and circumstances involved.
    (e)(1) EPA may withdraw its approval of the aggregate approach for 
the area and feedstocks in question if:
    (i) EPA determines that the data submitted pursuant to the plan 
described in paragraph (b)(7) of this section does not demonstrate that 
the amount of cropland and pastureland within the geographic boundaries 
covered by the approved petition does not exceed the 2007 baseline 
amount of land;
    (ii) EPA determines based on other information that the criterion 
specified in paragraph (a) of this section is no longer satisfied; or
    (iii) EPA determines that the data needed for its annual evaluation 
has not been collected and submitted in a timely and appropriate 
manner.
    (2) If EPA withdraws its approval, then producers using feedstocks 
from that area will be subject to the individual recordkeeping and 
reporting requirements of Sec.  80.1454(b) through (d) in accordance 
with the schedule specified in Sec.  80.1454(g).

[FR Doc. 2010-17281 Filed 7-19-10; 8:45 am]
BILLING CODE 6560-50-P

