[Federal Register Volume 75, Number 138 (Tuesday, July 20, 2010)]
[Proposed Rules]
[Pages 42238-42268]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-17281]
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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
Federal Register / Vol. 75 , No. 138 / Tuesday, July 20, 2010 /
Proposed Rules
[[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: [email protected].
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: [email protected], or Assessment and Standards
Division Hotline; telephone number 734-214-4636; E-mail address
[email protected].
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
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volume of cellulosic biofuel production is less than the required
volume specified in the statute, EPA must lower the required volume
used to set the annual cellulosic biofuel percentage standard to the
projected volume of production. We must also determine whether the
advanced biofuel and/or total renewable fuel volumes should be reduced
by the same or a lesser amount. Since these evaluations will be based
on evolving information about emerging segments of the biofuels
industry, and may result in the required volumes differing from those
in the statute, we believe that a notice-and-comment rulemaking process
is appropriate. Today's notice provides our evaluation of the projected
production of cellulosic biofuel for 2011, and proposed percentage
standards for compliance year 2011. We will complete our evaluation
based on comments received in response to this proposal, the Production
Outlook Reports due to the Agency on September 1, 2010, the estimate of
projected biofuel volumes that the EIA is required to provide to EPA by
October 31, and other information that becomes available, and will
finalize the standards for 2011 by November 30, 2010.
Today's proposed rule does not include an assessment of the
environmental impacts of the standards we are proposing for 2011. All
of the impacts of the RFS2 program were addressed in the RFS2 final
rule published on March 26, 2010, including impacts of the biofuel
standards specified in the statute. Today's rulemaking simply proposes
the standards for 2011 whose impacts were already analyzed previously.
Today's notice also presents two proposed changes to the RFS2
regulations. The first would create a temporary and limited means for
certain renewable fuel producers to generate RINs after they have
produced and sold renewable fuel. This proposed provision for ``Delayed
RINs'' would apply only to those producers who use canola oil, grain
sorghum, pulpwood, or palm oil to produce renewable fuel, and only if
EPA determines that fuel pathways utilizing these feedstocks provide
appropriate greenhouse gas reductions as compared to baseline fuels to
enable EPA to list the pathways in Table 1 to 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]
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Ethanol
Actual equivalent
volume volume
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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
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\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
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final rule to be released by November 30, 2010.
B. Assessment of 2011 Cellulosic Biofuel Volume
To estimate the volume of cellulosic biofuel that could be made
available in the U.S. in 2011, we researched all potential production
sources by company and facility. This included sources that were still
in the planning stages, those that were under construction, and those
that are already producing some volume of cellulosic ethanol,
cellulosic diesel, or some other type of cellulosic biofuel. We
considered all pilot and demonstration plants as well as commercial
plants. From this universe of potential cellulosic biofuel sources we
identified the subset that had a possibility of producing some volume
of qualifying cellulosic biofuel for use as transportation fuel in
2011. We then conducted a rigorous process of contacting all of these
producers to determine which ones were actually in a position to
produce and make available any commercial volumes of cellulosic biofuel
in 2011. Based on information gathered in this process, we estimated
the maximum potentially available 2011 volumes. For the final rule, we
will specify the projected available volume for 2011 that will be the
basis for the percentage standard for cellulosic biofuel. To determine
the projected available volume, we will consider factors such as the
current and expected state of funding, the status of the technology and
contracts for feedstocks, and progress towards construction and
production goals. A complete list of all the factors we expect to
consider in this process is provided in Section II.A.5.
In our assessment we evaluated both domestic and foreign sources of
cellulosic biofuel. Of the domestic sources, we estimated that seven
facilities have the potential to make volumes of cellulosic biofuel
available for transportation use in the U.S. in 2011. We also
determined that one facility in Canada has the potential to export some
cellulosic biofuel to the U.S. These facilities are listed in Table
I.B-1 along with our estimate of the maximum potentially available
volume.
Table I.B-1--Maximum Potentially Available Cellulosic Biofuel Plant Volumes for 2011
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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
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Total............................ ....................... ....................... 25.5
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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.
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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.
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\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.
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The general steps of the gasification thermochemical process
include: feedstock handling, gasification, gas cleanup and
conditioning, fuel synthesis, and separation. Refer to Figure IV.C.2-1
for a schematic of the thermochemical cellulosic ethanol production
process through gasification. For greater detail on the thermochemical
mixed-alcohols route refer to NREL technical documentation.\25\
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\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