[Federal Register Volume 78, Number 115 (Friday, June 14, 2013)]
[Proposed Rules]
[Pages 36041-36078]
[FR Doc No: 2013-12714]

Vol. 78

Friday,

No. 115

June 14, 2013

Part II

Environmental Protection Agency

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40 CFR Part 80

 Regulation of Fuels and Fuel Additives: RFS Pathways II and Technical
Amendments to the RFS 2 Standards; Proposed Rule

Federal Register / Vol. 78 , No. 115 / Friday, June 14, 2013 /
Proposed Rules

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 80

[EPA-HQ-OAR-2012-0401; FRL-9816-3]
RIN 2060--AR21

Regulation of Fuels and Fuel Additives: RFS Pathways II and
Technical Amendments to the RFS 2 Standards

AGENCY: Environmental Protection Agency (EPA).

ACTION: Notice of Proposed Rulemaking.

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SUMMARY: In this Notice of Proposed Rulemaking, EPA is proposing
amendments to three separate sets of regulations relating to fuels.
First, EPA is proposing to amend certain of the renewable fuels
standard (RFS2) program regulations. We believe these proposals will
facilitate the introduction of new renewable fuels as well as improve
implementation of the program. This proposal includes various changes
related to biogas, including changes related to the revised compressed
natural gas (CNG)/liquefied natural gas (LNG) pathway and amendments to
various associated registration, recordkeeping, and reporting
provisions. This proposed regulation includes the addition of new
pathways for renewable diesel, renewable naphtha, and renewable
electricity (used in electric vehicles) produced from landfill biogas.
Adding these new pathways will enhance the ability of the biofuels
industry to supply advanced biofuels, including cellulosic biofuels,
which greatly reduce the greenhouse gas emissions (GHG) compared to the
petroleum-based fuels they replace. It also addresses ``nameplate
capacity'' issues for certain production facilities that do not claim
exemption from the 20% greenhouse gas (GHG) reduction threshold. In
this notice, EPA addresses issues related to crop residue and corn
kernel fiber and proposes an approach to determining the volume of
cellulosic RINs produced from various cellulosic feedstocks. We also
include a lifecycle analysis of advanced butanol and discuss the
potential to allow for commingling of compliant products at the retail
facility level as long as the environmental performance of the fuels
would not be detrimental. Several other amendments to the RFS2 program
are included.
    Second, EPA is also proposing various changes to the E15 misfueling
mitigation regulations (E15 MMR). Among the E15 changes proposed are
technical corrections and amendments to sections dealing with labeling,
E15 surveys, product transfer documents, and prohibited acts. We also
propose to amend the definitions in order to address a concern about
the rounding of test results for ethanol content violations.
    Lastly, EPA is proposing changes to the survey requirements
associated with the ultra-low sulfur diesel (ULSD) program.

DATES: Comments must be received on or before July 15, 2013. We do not
expect a request for a public hearing. However, if we receive a request
for a public hearing by July 1, 2013 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-2012-0401, by one of the following methods:
     http://www.regulations.gov. Follow the on-line
instructions for submitting comments.
     Email<EMAIL_ADDRESS>Attention Air and Radiation
Docket ID No. EPA-HQ-OAR-2012-0401.
     Mail: Air and Radiation Docket, Docket No. EPA-HQ-OAR-
2012-0401, Environmental Protection Agency, Mail code: 6406J, 1200
Pennsylvania Ave. NW., Washington, DC 20460. Please include a total of
two (2) copies.
     Hand Delivery: EPA Docket Center, EPA/DC, EPA West, Room
3334, 1301 Constitution Ave. NW., Washington, DC 20460, Attention Air
and Radiation Docket, ID No. EPA-HQ-OAR-2012-0401. 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-
2012-0401. EPA's policy is that all comments received will be included
in the public docket without change and may be made available online at
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 www.regulations.gov or email. The
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 email comment
directly to EPA without going through www.regulations.gov, your email
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.
    Docket: All documents in the docket are listed in the
www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
for which 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 www.regulations.gov or in hard copy at the Air and
Radiation Docket, 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<PHONE_NUMBER>, and the
telephone number for the Air and Radiation Docket is<PHONE_NUMBER>.

FOR FURTHER INFORMATION CONTACT: Joseph Sopata, Chemist, Office of
Transportation and Air Quality, Mail Code: 6406J, U.S. Environmental
Protection Agency, 1200 Pennsylvania Avenue NW., 20460; telephone
number:<PHONE_NUMBER>; fax number:<PHONE_NUMBER>; email address:
<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION: This preamble follows the following outline:

I. Why is EPA taking this action?
II. Does this action apply to me?
III. What should I consider as I prepare my comments for EPA?
IV. Executive Summary
V. Renewable Fuel Standard (RFS2) Program Amendments
    A. Approving Cellulosic Volumes From Cellulosic Feedstocks
    1. Variability in Cellulosic Content Estimates of Feedstocks
    2. Characteristics of the Amount of the Final Fuel Derived From
Cellulosic Materials
    3. Previous Precedents

    4. Alternative Approaches
    B. Lifecycle Greenhouse Gas Emissions Analysis for Renewable
Electricity, Renewable Diesel and Naphtha Produced From Landfill
Biogas
    1. Feedstock Production
    2. Determination of the Cellulosic Composition of Landfill
Biogas
    3. Fuel Production--General Considerations
    4. Fuel Production for Renewable Electricity
    5. Fuel Production, Transport and Tailpipe Emissions for
Renewable Diesel and Naphtha
    C. Proposed Regulatory Amendments Related to Biogas
    1. Changes Applicable to the Revised CNG/LNG Pathway From Biogas
    2. New Registration (Contract Requirements) for Renewable
Electricity and Fuels Produced From Biogas That Qualify as Renewable
Fuel and That are Registered for RIN Generation
    3. Changes Applicable to all Biogas Related Pathways for RIN
Generation
    4. Changes Applicable To Process Electricity Production
Requirement for the Biogas-Derived Cellulosic Diesel and Naphtha
Pathways
    D. Amendment to the Definition of ``Crop Residue'' and
Definition of a Pathway for Corn Kernel Fiber
    E. Consideration of Advanced Butanol Pathway
    1. Proposed New Pathway
    2. Butanol, Biobutanol, and Volatility Considerations
    F. Amendments to Various RFS2 Compliance Related Provisions
    1. Proposed Changes to Definitions
    2. Provisions for Small Blenders of Renewable Fuels
    3. Proposed Changes to Section 80.1450--Registration
Requirements
    4. Proposed Changes to Section 80.1452--EPA Moderated
Transaction System (EMTS) Requirements--Alternative Reporting Method
for Sell and Buy Transactions for Assigned RINs
    5. Proposed Changes to Section 80.1463--Confirm That Each Day an
Invalid RIN Remains in the Market is a Separate Day of Violation
    6. Proposed Changes to Section 80.1466--Require Foreign Ethanol
Producers, Importers and Foreign Renewable Fuel Producers That Sell
to Importers to be Subject to U.S. Jurisdiction and Post a Bond
    7. Proposed Changes to Section 80.1466(h)--Calculation of Bond
Amount for Foreign Renewable Fuel Producers, Foreign Ethanol
Producers and Importers
    8. Proposed Changes to Facility's Baseline Volume To Allow
``Nameplate Capacity'' for Facilities not Claiming Exemption From
the 20% GHG Reduction Threshold
    G. Minor Corrections to RFS2 Provisions
VI. Amendments to the E15 Misfueling Mitigation Rule
    A. Proposed Changes to Section 80.1501--Label
    B. Proposed Changes to Section 80.1502--E15 Survey
    C. Proposed Changes to Section 80.1503--Product Transfer
Documents
    D. Proposed Changes to Section 80.1504--Prohibited Acts
    E. Proposed Changes to Section 80.1500--Definitions
VII. Proposed Amendments to the ULSD Diesel Survey
VIII. Statutory and Executive Order Reviews

I. Why is EPA taking this action?

    EPA is taking this action to amend various provisions in its
regulations pertaining to fuels and fuel additives. First, EPA is
proposing to amend 40 CFR part 80, subpart M related to the renewable
fuels standard (RFS2). The RFS2 program was required by the Energy
Independence and Security Act of 2007 (EISA 2007), which amended the
Clean Air Act (CAA). The final regulations for RFS2 were published in
the Federal Register on March 26, 2010 (75 FR 14670). In this notice,
references to the ``RFS2 final rule'' refer to the March 26, 2010
Federal Register notice unless otherwise noted. Second, EPA is
proposing to amend provisions of 40 CFR part 80, subpart N, related to
misfueling mitigation for 15 volume percent (%) ethanol blends (E15).
The final regulations for E15 were published in the Federal Register on
July 25, 2011 (76 FR 44422). Several items in this proposed action will
assist regulated parties in complying with RFS2 and E15 requirements.
This action is not expected to result in significant changes in
regulatory burdens or costs associated with the RFS2 and E15 programs.
Third, EPA is proposing a change to the ultra low sulfur diesel (ULSD)
program of 40 CFR part 80, subpart I. Specifically, EPA is proposing an
amendment to the survey provisions that would likely result in
decreasing the number of samples that must be taken, and as such would
be expected to result in a decrease in regulatory burdens or costs.

II. Does this action apply to me?

    Entities potentially affected by this action include those involved
with the production, distribution and sale of transportation fuels,
including gasoline and diesel fuel, or renewable fuels such as ethanol
and biodiesel. Regulated categories and entities affected by this
action include:

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                                               NAICS Codes                    Examples of potentially regulated
                  Category                         \a\        SIC Codes \b\                parties
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Industry...................................          324110            2911  Petroleum refiners, importers.
Industry...................................          325193            2869  Ethyl alcohol manufacturers.
Industry...................................          325199            2869  Other basic organic chemical
                                                                              manufacturers.
Industry...................................          424690            5169  Chemical and allied products
                                                                              merchant wholesalers.
Industry...................................          424710            5171  Petroleum bulk stations and
                                                                              terminals.
 Industry..................................          424720            5172  Petroleum and petroleum products
                                                                              merchant wholesalers.
Industry...................................          454319            5989  Other fuel dealers.
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\a\ North American Industry Classification System (NAICS).
\b\ 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
action. This table lists the types of entities that EPA is now aware
could be potentially regulated by this action. Other types of entities
not listed in the table could also be regulated. To determine whether
your entity is regulated by this action, you should carefully examine
the applicability criteria of Part 80, subparts I, M and N of Title 40
of the Code of Federal Regulations. If you have any question regarding
applicability of this action to a particular entity, consult the person
in the preceding FOR FURTHER INFORMATION CONTACT section above.

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

    A. Submitting CBI. Do not submit this information to EPA through
www.regulations.gov or email. 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.
    B. 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.
    C. Docket Copying Costs. You may be charged a reasonable fee for
photocopying docket materials, as provided in 40 CFR part 2.

IV. Executive Summary

    EPA is proposing amendments to three sets of regulations. First,
EPA is proposing to amend certain of the renewable fuels standard
(RFS2) program regulations at 40 CFR part 80, Subpart M. Section V of
this preamble includes several proposed amendments to the RFS2
regulations of 40 CFR part 80. The final regulations for RFS2 were
published in the Federal Register on March 25, 2010 (75 FR 14670). EPA
has issued technical corrections in the past. We have identified
several additional changes. Some of the proposed changes in this notice
are of a substantive nature; others are more in the nature of technical
corrections, including corrections of obvious omissions and errors in
citation. Among the more substantive modifications are various proposed
changes related to biogas, including changes related to the revised
compressed natural gas (CNG)/liquefied natural gas (LNG) pathway and
amendments to various associated registration, recordkeeping, and
reporting provisions. These fuels have the potential to add notable
volumes of advanced biofuel including cellulosic biofuel to the
existing renewable fuel volumes already being produced. Many of these
changes are being proposed in order to facilitate the introduction of
new renewable fuels under the RFS2 program and have come at the
suggestion of industry stakeholders.
    This preamble includes the addition of new pathways for renewable
diesel, and renewable naphtha, and renewable electricity (used in
electric vehicles) produced from landfill biogas. It includes a
proposal to address ``nameplate capacity'' issues for certain
production facilities that do not claim exemption from the 20%
greenhouse gas (GHG) reduction threshold. EPA proposes to address
issues related to crop residue and corn kernel fiber. We propose an
approach for approving the cellulosic volumes from cellulosic
feedstocks. We include a lifecycle analysis of advanced butanol and
discuss the potential to allow for commingling of compliant products at
the retail facility level as long as the environmental performance of
the fuels would not be detrimental when compared to existing practices.
We specifically discuss this consideration for commingling in regards
to the volatility associated with butanol gasoline and ethanol gasoline
blends.
    We state when and how EPA may cancel a company registration. Of a
more minor scope, this preamble includes proposed amendments that would
define terminology used for registration and reporting purposes and
propose changes to registration and reporting requirements. This
preamble also discusses some minor corrections, including adding
language to registration, recordkeeping and reporting sections
requiring English language translation of documents. We have also
proposed to correct obvious omissions and errors in citation in the
existing RFS2 regulation.
    Second, EPA is also proposing various changes to the E15 misfueling
mitigation regulations (E15 MMR) at 40 CFR part 80, subpart N. The
final E15 MMR was published in the Federal Register on July 25, 2011
(76 FR 44406). Among the E15 changes proposed are technical corrections
and amendments to sections dealing with labeling, E15 surveys, product
transfer documents, and prohibited acts. We also propose to amend the
definitions in order to address a concern about the rounding of Reid
Vapor Pressure (RVP) test results, in response to a question raised by
some industry stakeholders.
    Third, in response to questions received from regulated parties, we
propose to amend the ultra low sulfur diesel (ULSD) survey provisions
in a manner that will likely reduce the number of samples required.
This may mean a reduction in costs and burdens associated with
compliance for regulated parties, with no expected degradation in the
highly successful environmental performance of the program.

V. Renewable Fuel Standard (RFS2) Program Amendments

    The RFS2 program was required by the Energy Independence and
Security Act of 2007 (EISA 2007), which amended the Clean Air Act
(CAA). The final regulations for RFS2 were published in the Federal
Register on March 26, 2010 (75 FR 14670). The rule took effect on July
1, 2010. In this notice, we are proposing several new renewable fuel
pathway options for advanced biofuels including new cellulosic biofuel
pathways. This proposed regulation would also provide modifications and
technical amendments to the existing RFS2 program.

A. Approving Cellulosic Volumes From Cellulosic Feedstocks

    Since the inception of the RFS program, EPA has qualified several
fuel pathways that are able to generate cellulosic biofuel RINs (D
codes 3 and 7). See 40 CFR 80.1426. Each of the qualified cellulosic
feedstocks listed in section 80.1426 contain other components such as
starches, sugars, lipids, and proteins. To date, EPA has not provided
detailed information on how other components should be treated. This
has led to uncertainty amongst renewable fuel producers about whether
their entire volume of fuel produced from a cellulosic feedstock would
be eligible to generate cellulosic RINs. In this rulemaking, EPA
proposes to allow 100% of the volume of renewable fuel produced from
certain specified, currently approved cellulosic feedstocks to generate
cellulosic (D-3 or D-7) RINs. We also take comment on two alternative
approaches for how to treat non-cellulosic components of cellulosic
feedstocks.
    For purposes of the RFS program, cellulosic biofuel is defined as
``renewable fuel derived from any cellulose, hemicellulose, or lignin
that is derived from renewable biomass and that has lifecycle
greenhouse gas emissions, as determined by the Administrator, that are
at least 60 percent less than the baseline lifecycle greenhouse gas
emissions.'' This

definition was added in Section 211(o)(1)(E) by the Energy Independence
and Security Act (EISA) of 2007, where Congress specified four
different categories of renewable fuel and their associated volume
requirements. The threshold for reduction in greenhouse gases is set at
a higher percentage for cellulosic biofuel than the reduction for the
other categories of renewable fuels. While the volume requirements for
cellulosic biofuel start at a relatively low volume, Congress specified
large volume increases over time such that the main growth in the use
of renewable fuels comes from cellulosic biofuels. This reflects a
strong Congressional intention to promote the use of cellulosic biofuel
and achieve the associated greenhouse gas emissions reductions.
    However, no plant matter can ever consist entirely of cellulose,
hemicellulose and lignin. Plants require proteins, DNA, carbohydrates
and many other types of compounds in order to grow and function. Even
feedstocks such as switchgrass, corn stover, and woody materials which
are the most commonly cited ``cellulosic'' feedstocks, contain
measurable proportions of other types of organic molecules. However,
these ``cellulosic'' feedstocks contain much more cellulose,
hemicellulose and lignin than do other types of biomass. As shown in
Table V.A.-1, most ``cellulosic'' feedstocks consist of approximately
80-95% cellulose, hemicellulose, or lignin.\1\ In contrast, corn
kernels contain roughly 75% starch and less than 10% fiber (which
includes the cellulosic components, as well as other materials),\2\ and
soybeans are roughly 60% oil and protein and only about 15% fiber.\3\
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    \1\ See Memorandum to Docket, ``Cellulosic Content of Various
Feedstocks,'' Docket EPA-HQ-OAR-2012-0401.
    \2\ Peplinski et al. (1992) Physical, chemical and dry-mill
properties of corn of varying density and breakage susceptibility.
Cereal Chemistry, 69(4), 397-400.
    \3\ Illinois Soybean Association. Facts and Statistics for the
Illinois Soybean Industry. http://www.ilsoy.org/_data/mediaCenter/files/1290.pdf.
    \4\ Values have been adjusted to account for the presence of
inorganic ash, which will not produce fuel, as described in the
Memorandum to the Docket, ``Cellulosic Content of Various
Feedstocks,'' Docket EPA-HQ-OAR-2012-0401.

   Table V.A.-1--Average Cellulosic Composition of Different Types of
                              Feedstocks\4\
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                                                       Average  adjusted
                                                           cellulosic
                    Feedstock type                        composition
                                                           (percent)
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Crop Residue.........................................                 90
Switchgrass..........................................                 85
Miscanthus...........................................                 85
Other Grasses........................................                 81
Wood and Branches....................................                 92
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    EPA is proposing to allow 100% of the volume of renewable fuel
produced from specific cellulosic feedstock sources found in Table 1 of
section 80.1426 to generate D-3 or D-7 RINs (depending on the type of
finished fuel). However separated food waste, separated yard waste, and
separated MSW would continue to be treated as before, as discussed
below. There are three major justifications for this determination: (1)
There can be significant variation in the amount of cellulosic content
in any feedstock, which varies within a growing season, across samples,
and across sites. Attempting to account for this variability would
impose a significant administrative burden on producers and EPA; (2)
The amount of the final fuel that is produced from the cellulosic
portion of the feedstock is likely to be very high, particularly for
fuels produced using a biochemical reaction; (3) EPA has already made
previous determinations in which a single RIN value was assigned to the
fuel produced since it came primarily from one source even though it
was also produced from incidental amounts of other sources.
    This determination is based on the view that the statutory
requirement does not mandate that in all cases the renewable fuel must
be produced solely from the cellulosic material in the renewable
biomass. EPA considers the statutory definition of cellulosic biofuel
to be flexible on this point. Given these factors cited above, the
Agency believes this interpretation of ``derived from'' is consistent
with the Congressional intent to require increased use of cellulosic
biofuels while ensuring that the program can be implemented in a
reasonable way. Details on the variability in feedstocks,
characteristics of the final fuel, previous precedents, and alternative
proposals are included in the following sections.
1. Variability in Cellulosic Content Estimates of Feedstocks
    The cellulosic components of feedstock consist of the major
structural components; cellulose; hemicellulose; and lignin. EPA has
reviewed research characterizing the different components of
feedstocks, mainly focused on how the materials could be broken down
and converted into fuel. There has been work also in defining
standardized procedures and test methods for analyzing the different
components of biomass; \5\ however, the studies considered all employ
slightly different methods. For the purposes of this rule, EPA
considered the amount of the feedstocks that is composed of cellulosic
components i.e., how much comes from the cellulose, hemicellulose or
lignin, as opposed to any other components of the feedstock. There is
significant variation in the data reported on feedstock component
compositions. The variation is due to a number of causes, such as
measurement methods,6 7 variety within a generic feedstock
type, and storage time.\8\
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    \5\ See, e.g., the Standard Biomass Analytical Procedures
developed by the National Renewable Energy Laboratory, http://www.nrel.gov/biomass/analytical_procedures.html.
    \6\ Compositional Analysis of Lignocellulosic Feedstocks. 2.
Method Uncertainties, David W. Templeton, Christopher J. Scarlata,
Justin B. Sluiter, And Edward J. Wolfrum, J. Agric. Food Chem. 2010,
58, 9054-9062
    \7\ Relative standard deviations (RSD) of 5-8% are reported for
cellulose, hemicelluloses and lignin with the other minor components
showing 16-22% RSD.
    \8\ Composition of Herbaceous Biomass Feedstocks, DoKyoung Lee,
Vance N. Owens, Arvid Boe, Peter Jeranyama, Plant Science
Department, South Dakota State University, SGINC1-07, June 2007.
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    Although there are many factors that contribute to the large
variability in assessments of cellulosic content, all studies confirm
that the feedstocks in Table 1 of section 80.1426 have an adjusted
cellulosic content of at least 70%, with an average content of around
85% cellulosic.\9\ A memorandum to the docket provides more information
on cellulosic terminology, percent composition of various feedstocks,
and the variability of different feedstock components.\10\ From this
data, EPA concludes that each of the qualified feedstocks listed in
section 80.1426 are comprised predominantly of cellulose, hemicellulose
and lignin.
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    \9\ EPA only considered the organic components of the materials
when determining cellulosic content. Inorganic materials are not
likely to end up in the final fuel product and would not contribute
to the fuel heating content in the event that they remained in the
final fuel. This methodology is consistent with how RINs are
determined. In this section, EPA refers to this as ``adjusted
cellulosic.'' Adjusted cellulosic content does not consider other
material that is not converted into biofuel such as minerals or
other components that would show up as part of the ash remaining
after a thermo-chemical conversion process.
    \10\ See Memorandum to Docket, ``Cellulosic Content of Various
Feedstocks,'' Docket EPA-HQ-OAR-2012-0401.

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2. Characteristics of the Amount of the Final Fuel Derived From
Cellulosic Materials
    Process technology plays a key role in how much of the final fuel
product is actually produced from cellulose, hemicellulose, or lignin.
There are two basic processes for converting cellulosic feedstocks into
fuel: thermo-chemical and biochemical. Thermo-chemical processes mainly
consist of pyrolysis--in which cellulosic biomass is decomposed with
temperature to bio-oils and could be further processed to produce a
finished fuel--and gasification--in which cellulosic biomass is
decomposed to synthesis gas (``syngas'') with further catalytic
processing to produce a finished fuel product. The biochemical process
requires the release of sugars from biomass and the use of
microorganisms to convert sugars into fuels. Thermo-chemical processes
can accept a more heterogeneous mix of feedstock and typically convert
all of the organic components of the feedstock into finished fuel. The
biochemical process generally accepts a more homogeneous mix of
feedstocks and typically converts only the cellulosic and
hemicellulosic components of the feedstock into the final fuel product.
Therefore, regardless of the feedstock used, the final fuel produced
from the biochemical process will typically only come from the
cellulosic or hemicellulosic portions of feedstock, while the final
fuel produced from the thermo-chemical process could come from
cellulosic and non-cellulosic components.
    For thermo-chemical production in which the non-cellulosic
components of the feedstock can contribute to the volume of fuel
produced in addition to the cellulosic components, the percent of fuel
produced from the non-cellulosic portion can vary due to such factors
as feedstock type and the time and location of feedstock harvest.
Regardless, we believe that the majority of the fuel produced will be
from the cellulosic components. As a practical matter, there is no
simple test that can be used to measure the amount of fuel end product
that originated from cellulosic materials. For fuel produced via the
biochemical process, 100% of the fuel produced is directly the result
of conversion of the cellulosic content.
    In selecting a cellulosic process, whether based on biochemical or
thermo-chemical design, the fuel producer is clearly demonstrating that
its primary intent is to convert the cellulosic portions of the
feedstock. Cellulosic fuel producers invest in expensive process
technologies with the intent of converting the cellulosic components of
a feedstock into fuel; conversion of the non-cellulosic components can
be achieved much more easily with less of a capital investment.
Furthermore, since the fuel produced will be primarily the result of
the direct conversion of cellulosic content of the feedstock and
considering the relatively small range of non-cellulosic portion of
feedstock that could contribute to the volume of fuel produced, EPA
believes it is reasonable to consider all the fuel produced when
relying on cellulosic conversion processes to be cellulosic biofuel.
3. Previous Precedents
    EPA has already considered instances where one RIN value was
assigned to the fuel produced since it came primarily from one source
even though it was also produced from some amount of other chemical
compounds. In the March 2010 RFS rulemaking, EPA discussed two
different situations for fuel produced from separated yard waste and
food waste as the renewable biomass feedstock. The first involved food
waste or yard waste that was kept separate, from generation, from
municipal solid waste (MSW). EPA determined that both of these
feedstocks could be considered renewable biomass. With respect to
separated yard waste, EPA determined that the yard waste was expected
to be composed almost entirely of woody material or leaves, and this
would be deemed to be cellulosic material and would generate cellulosic
biofuel RINs. Separated food waste, however, was likely to be composed
of both cellulosic and non-cellulosic materials, and in certain cases
would likely be composed primarily of non-cellulosic materials, such as
sugars and starches from the food. EPA determined that separated food
waste would be deemed to be non-cellulosic material, and would generate
advanced biofuel RINs and not cellulosic RINs, unless the renewable
fuel producer demonstrated the part of the food waste that was
cellulosic. This portion would then generate cellulosic RINs.\11\
---------------------------------------------------------------------------

    \11\ 75 FR 14670, 14706 (March 26, 2010).
---------------------------------------------------------------------------

    The second situation EPA previously addressed involved separated
MSW. EPA determined that separated MSW that met certain regulatory
requirements would qualify as a renewable biomass for purposes of
producing renewable fuel. EPA recognized that the biogenic portion of
this feedstock would be composed of a ``variety of materials, including
yard waste (largely cellulosic) and food waste (largely starches and
sugar), as well as incidental materials remaining after reasonably
practicable separation efforts such as plastic and rubber of fossil
origin.'' Testing could identify the portion of the fuel produced from
biogenic materials, and these biogenic materials ``will likely be
largely derived from cellulosic materials (yard waste, textiles, paper,
and construction materials), and to a much smaller extent starch-based
materials (food wastes).'' However, EPA was not aware of a test method
to distinguish between renewable fuel produced from the cellulose and
fuel produced from the starch and under those circumstances determined
that it was appropriate to base the assignment of RINs on the
``predominant'' component of the biogenic material. EPA thus determined
that all of the fuel generated from the biogenic portion of separated
MSW would be considered cellulosic biofuel.\12\
---------------------------------------------------------------------------

    \12\ 75 FR at 14706.
---------------------------------------------------------------------------

    Thus, EPA has interpreted the definition of cellulosic biofuel as
including in some cases a renewable fuel that is produced from both the
cellulosic and incremental amounts of non-cellulosic components of the
feedstock. EPA has treated the resulting fuel as all derived from
cellulosic material where the feedstock is composed almost entirely of
woody materials and leaves, or where the predominant component of the
feedstock is likely cellulosic. The fuel will be largely derived from
this cellulosic material and to a much smaller extent from non-
cellulosic materials. There currently is no ready test to identify the
portion of fuel produced from non-cellulosic materials. EPA has not
considered the fuel as cellulosic in cases where the feedstock was
likely to be largely non-cellulosic materials. In all of these cases,
EPA has recognized that the fuel would be produced from both the
cellulosic and non-cellulosic materials in the feedstock, and has
determined in some cases to consider the fuel entirely cellulosic
biofuel based on the relative amounts of the cellulosic and non-
cellulosic materials and, for fuel made from the biogenic portion of
separated MSW, on the lack of availability of a test procedure to
differentiate how much of the fuel came from the cellulosic materials.
    These determinations have been based on the view that the statutory
requirement that cellulosic biofuel be ``derived from cellulose,
hemicellulose, or lignin'' does not mandate that in all cases the
renewable fuel must be produced solely from the cellulosic material in
the renewable biomass. EPA

considers the statutory definition of cellulosic biofuel to be
ambiguous on this point, providing EPA the discretion to reasonably
determine under what circumstances a fuel appropriately could be
considered cellulosic biofuel when the fuel is produced from a
feedstock that is a mixture of cellulosic and non-cellulosic materials.
To date, EPA has specified certain circumstances where the entire fuel
will be considered cellulosic biofuel. EPA has taken this action in
cases where the cellulosic material is almost entirely woody materials
or leaves, or the fuel is produced from materials that are
predominantly composed of cellulosic materials and to a much smaller
extent non-cellulosic materials, with no current test to identify the
differing portions. There have been two elements present in these
decisions. One involves a determination that the feedstock is composed
almost entirely or largely of cellulosic materials. EPA has also
considered whether or not there is a test method to identify the actual
portion of the fuel produced from cellulosic materials. In this
rulemaking EPA is proposing an approach that is consistent with and an
outgrowth of the approach taken in the RFS2 rulemaking. EPA is
proposing to approve certain fuels as cellulosic biofuel where the
cellulosic components account for a predominant percentage of the
biogenic material in the renewable biomass feedstock used to produce
the fuel, even where the non-cellulosic components of the renewable
biomass could be reasonably identified or estimated.\13\
---------------------------------------------------------------------------

    \13\ By predominant, EPA means the very high percentages for
adjusted cellulosic content discussed in section V.A.1. above for
the feedstocks at issue in this proposal.
---------------------------------------------------------------------------

    EPA is proposing to classify all of the biofuel as cellulosic in
the fuel pathways proposed today, where the cellulosic material makes
up a predominant percentage of the organic material from which the fuel
is produced. This approach will avoid the administrative and technical
burden on producers and EPA of trying to determine the specific amounts
of cellulosic and non-cellulosic materials in the specified high-
cellulosic feedstock sources, removing potential difficult and
potentially time-consuming and expensive impediment to expansion of the
cellulosic biofuel industry. The growth in cellulosic biofuel volumes
promoted by today's proposal is expected to result in greater
reductions in GHGs, as all of the biofuel qualified as cellulosic would
have to achieve the minimum 60% reduction in GHG emissions specified in
the Act. EPA's application of this approach to the specific fuel
pathways and feedstocks discussed in this proposal is intended to
ensure that cellulosic materials are the predominant portion of the
biogenic materials used to produce cellulosic biofuel. This approach
avoids administrative, technical and cost burdens on EPA and industry
and promotes the volume and greenhouse gas objectives of Congress. EPA
proposes that this is a reasonable interpretation of the definition of
cellulosic biofuels, and invites comment on this approach.\14\
---------------------------------------------------------------------------

    \14\ See Bot v. IRS, 353 F.3d 595 (8th Cir. 2003), Wuebker v.
IRS, 205 F.2d 897 (6th Cir. 2000), Milligan v. IRS, 38 F.3d 1094
(9th Cir. 1994). See also Hecla Mining Company v. US, 909 F.2d 1371
(10th Cir. 1990) (DOE's interpretation of the term ``derived from''
in the Uranium Mill Tailings Radiation Control Act of 1978 accepted
as a reasonable interpretation under Chevron).
---------------------------------------------------------------------------

    EPA is proposing that biofuel made from the following cellulosic
feedstocks will be able to generate applicable cellulosic RINs for 100%
of the volume produced: crop residue; slash; pre-commercial thinnings
and tree residue; annual cover crops; switchgrass; miscanthus; and
energy cane. EPA's prior treatment of separated yard waste, separated
food waste, and separated MSW is discussed above and is not being
changed. On January 5, 2012, EPA proposed to qualify napier grass and
Arundo donax as new feedstocks that would be eligible to generate
cellulosic RINs. If those pathways are approved before this rule is
final, EPA is proposing to apply the approach discussed above to these
feedstocks as well.\15\ To the extent that additional cellulosic
pathways are approved in the future, we would expect to apply this same
methodology to those feedstocks as well, but will evaluate them on a
case-by-case basis.
---------------------------------------------------------------------------

    \15\ In addition, in section B of this proposal, EPA is also
proposing to include corn fiber, CNG, LNG, electricity, and
renewable diesel and naphtha from landfill biogas as cellulosic
pathways for the reasons discussed therein.
---------------------------------------------------------------------------

    EPA requests comments on this proposed approach to allow 100% of
the volume of renewable fuel produced from the specified cellulosic
feedstock sources found in Table 1 of section 80.1426 to generate
cellulosic RINs. We also take comment on the cellulosic content values
presented for different feedstocks. In addition, we request comments
about any analytical methods that may exist to determine what percent
of a finished biofuel product may have derived from cellulosic versus
non-cellulosic components, and what the costs may be associated with
these test methods. We also request comment on the alternative
approaches outlined below.
4. Alternative Approaches
    EPA seeks comment on two alternative approaches to assigning
cellulosic RINs to fuels produced from the cellulosic feedstocks
discussed above. Separate from the specific pathways addressed in this
proposal, EPA also seeks comment on potential approaches for assigning
cellulosic RINs for anticipated future pathways for renewable fuels
produced from feedstocks that contain lower cellulosic content than
those discussed in this rulemaking.
Cellulosic Content Threshold Approach
    An alternative approach for handling the variability in cellulosic
content would be for EPA to set a minimum threshold of cellulosic
content in the feedstock. Fuels produced from feedstocks with a
cellulosic content above this minimum threshold would be eligible to
generate cellulosic RINs for 100% of their volume. Thresholds under
consideration would range from 70% to 99.9%. A higher percentage would
place more emphasis on the feedstock content having a higher actual
cellulosic component, whereas the lower percentages would place more
emphasis on promoting the volume of fuels that could be categorized as
cellulosic biofuel. EPA invites comment on this approach, and also
invites comment on the most appropriate value to use as the threshold.
Furthermore, EPA invites comment on whether individual producers should
be responsible for submitting data that their feedstock meets this
threshold, or whether EPA should determine whether feedstocks meet this
threshold based on existing published data.
    Since biochemical processes generally only convert the cellulosic,
hemicellulosic, or lignin components of the feedstock to fuel, EPA
believes under this alternative approach, it may still be appropriate
to allow fuel producers using biochemical processes to generate RINs
for 100% of the fuel produced from cellulosic feedstocks. EPA requests
comments on our assumption that biochemical processes will be specific
for the cellulosic components, and we also request comment on whether
to allow 100% of the fuel produced via biochemical processes to
generate cellulosic RINs.
Specified Percentage Approach
    As noted above, examining the range of feedstock data compiled by
EPA, it appears that 85% would be a reasonable approximation for the
average adjusted

cellulosic content across a range of assessments of the specific
feedstocks that are qualified to produce cellulosic fuel. Under this
approach, fuels produced from the cellulosic feedstocks discussed above
would be eligible to generate cellulosic RINs for 85% of their volume,
and the remaining 15% would be eligible to generate advanced RINs. The
specified percentage approach would reduce administrative burden but
also incentivize renewable fuel production. For this approach, EPA
would effectively be treating 85% of the fuel produced from all of
these feedstock sources as being derived from cellulosic material.
However, EPA would consider allowing a larger percentage of the fuel to
qualify for cellulosic RINs if the producer could submit data that
demonstrates a consistently higher cellulosic content in their
feedstock. Under this approach, producers could submit a written plan
for approval under the registration procedures in 40 CFR
80.1416(b)(vii). The plan would need to detail the cellulosic content
of the feedstock, the method used for quantifying the cellulosic and
non-cellulosic contents, and the production process used.
    Since biochemical processes generally only convert the cellulose,
hemicellulose, or lignin components of the feedstock to fuel, EPA
believes under this alternative approach it would be appropriate to
allow fuel producers using biochemical processes to generate RINs for
100% of the fuel produced from cellulosic feedstocks. EPA requests
comments on our assumption that biochemical processes will be specific
for the cellulosic components, and we also request comment on whether
to allow 100% of the fuel produced via biochemical processes to
generate cellulosic RINs.
Request for Comment on Potential Approaches for Fuels Produced From
Feedstocks With Lower Cellulosic Content
    Finally, EPA anticipates that in the future, we may address
biofuels that are produced from feedstocks that contain lower
cellulosic content than those discussed in this rulemaking.
Accordingly, we request comment on how EPA should assign RINs to the
fuels produced from feedstocks with lower cellulosic content than those
presented in this rulemaking but for which some of the fuel is produced
from the cellulosic components. One possible example would be a
feedstock that contained in the range of 40-60% cellulose,
hemicellulose and lignin, where the fuel was produced using
thermochemical methods such that the same percentage of the fuel may
come from cellulosic materials. EPA invites comments about what
approaches could be taken for assigning cellulosic RINs to the biofuel.
For example, would one or more of the approaches outlined above be
appropriate for assigning RINs to this fuel? Are there variations on
these approaches that EPA should consider? EPA also invites comments on
how to assign cellulosic RINs where processes other than thermochemical
methods are used.

B. Lifecycle Greenhouse Gas Emissions Analysis for Renewable
Electricity, Renewable Diesel and Naphtha Produced from Landfill Biogas

    EPA has received several facility-specific petitions under Sec.
80.1416 to allow renewable electricity, renewable diesel and naphtha
produced from landfill biogas to qualify as renewable fuels under the
RFS program. Since these new pathways could be more broadly applicable,
EPA is proposing to add these pathways to Table 1 to Sec.  80.1426
through this rulemaking process. Based on questions from companies, EPA
is also modifying the existing biogas pathway to specify that
compressed natural gas (CNG) or liquefied natural gas (LNG) is the fuel
and biogas is the feedstock. For this proposal, EPA considered both the
cellulosic origin of landfill biogas and the lifecycle GHG impacts of
three types of fuel produced from landfill-derived biogas. In the final
RFS2 rule, EPA established biogas as a fuel type when derived from
landfills, sewage waste treatment plants, and manure digesters. This
biogas was classified as an advanced biofuel eligible to generate D-
Code 5 RINs. EPA also established cellulosic diesel and cellulosic
naphtha as cellulosic biofuels eligible to generate D-Code 7 and 3
RINs, respectively. The eligible feedstocks for these biofuels include
cellulosic components of separated municipal solid waste but did not
include biogas from landfills.
    Based in part on additional information received through the
petition process for EPA approval of renewable electricity and
renewable diesel and naphtha produced from landfill biogas, EPA has
evaluated these pathways and is proposing to include renewable
electricity produced from landfill biogas feedstock in Table 1 to Sec.
80.1426 as a cellulosic fuel type. It is important to note that RINs
may only be generated for electricity from biogas that can be tracked
to use in the transportation sector, such as by an electric vehicle. We
are also proposing to add renewable diesel produced from landfill
biogas via the Fischer-Tropsch process as an approved advanced and/or
biomass-based diesel biofuel and naphtha produced from landfill biogas
via the Fischer-Tropsch process as an approved advanced biofuel. If the
Fischer-Tropsch facilities produce at least 20% of their electricity
demand at the facility from certain allowed sources, we are proposing
that the renewable diesel and naphtha produced would further qualify as
cellulosic biofuels. We are also proposing to amend the existing biogas
pathway to list renewable CNG/LNG as the fuel types instead of biogas
since the biogas is converted into CNG or LNG before being used as a
transportation fuel, as discussed below. Renewable CNG/LNG produced
from biogas from waste treatment plants and waste digesters is still
classified as an advanced biofuel. However, renewable CNG/LNG produced
from biogas from landfills now qualifies as a cellulosic pathway. The
changes to the renewable CNG/LNG pathway are described in section C.1.
``Changes Applicable to the Revised CNG/LNG pathway from Biogas''
below.
1. Feedstock Production
    When waste materials are buried in a landfill, decomposition of the
organic materials consumes all of the oxygen present within roughly one
year, leaving the bulk of the material to undergo slower, anaerobic
decomposition. This process produces large amounts of methane for
several decades, as well as other products, with the gases released as
``biogas.'' Biogas from landfills typically contains approximately 50%
methane and 50% carbon dioxide, with small or trace amounts of other
gases. Methane is a potent greenhouse gas (GHG), with a global warming
potential of 21 times that of carbon dioxide, and landfills are the
third-largest anthropogenic source of methane to the atmosphere in the
United States.\16\
---------------------------------------------------------------------------

    \16\ U.S. Environmental Protection Agency. 2013. Inventory of
U.S. Greenhouse Gas Emissions and Sinks: 1990-2011, Chapter 8:
Waste. EPA 430-R-13- 001, available at http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2013-Main-Text.pdf.
---------------------------------------------------------------------------

    The methane present in biogas is also a potential energy source
that may be purified and compressed to be used directly in CNG or LNG
vehicles, combusted to produce electricity or converted to renewable
diesel and naphtha via the Fischer-Tropsch process. The March 2010 RFS
final rule concluded that municipal solid waste has no agricultural or
land use change GHG emissions associated with its production.
Furthermore, the feedstock for these fuels is landfill biogas, which
already appears in Table 1 of

Sec.  80.1426(f) of the RFS2 regulations and has already been evaluated
as part of the RFS2 final rule lifecycle GHG determinations. Therefore
no new renewable feedstock production modeling was required, no GHG
emissions were attributed to feedstock production for any of these
renewable fuel pathways, and EPA focused our analysis on the new fuel
production processes.
2. Determination of the Cellulosic Composition of Landfill Biogas
    In order for fuels produced from landfill biogas as a feedstock to
qualify to generate D-Code 3 or 7 (cellulosic) RINs, the renewable fuel
must be derived from cellulosic materials and must meet a 60% GHG
emissions reduction threshold, as described in the following sections.
In this section, we discuss our determination that biogas derived from
landfills is derived from cellulose, hemicellulose or lignin.
    CAA 211(o) specifies ``separated yard waste or food waste'' as a
type of renewable biomass, and in the March 2010 RFS final rule, EPA
stated:

    As a result of the intermixing of wastes, the fact that biogas
is formed only from the biogenic portion of landfill material, and
the fact that landfill material is as a practical matter
inaccessible for further separation, EPA believes that no further
practical separation is possible for landfill material and biogas
should be considered as produced from separated yard and food waste
for purposes of EISA.

    The March 2010 RFS final rule stated that all landfill-derived
biogas was therefore eligible to generate RINs.
    An in-depth study of methane production from different chemical
components of municipal solid waste found that roughly 90% of the
methane generated in landfills derived was from cellulose and
hemicellulose.\17\ Accordingly, EPA is proposing to classify renewable
fuels produced from landfill biogas as derived from cellulose,
hemicellulose or lignin. This determination is discussed in more detail
in a memo to the docket.\18\ Consistent with the discussion in the
section above, ``Approving Cellulosic Volumes from Cellulosic
Feedstock,'' we are classifying all of the biofuel volume produced from
landfill biogas as cellulosic in origin. Therefore the entire volume of
renewable fuels using landfill biogas as a feedstock will be eligible
to generate cellulosic RINs (D-Codes 3 and 7) if the fuel also meets
the required 60% GHG emissions reductions. EPA invites comment and data
on the cellulosic component of biogas.
---------------------------------------------------------------------------

    \17\ Barlaz, M.A., R.K. Ham, and D.M. Schaefer. 1989. Mass-
balance analysis of anaerobically decomposed refuse. Journal of
Environmental Engineering, 15(6) 1088-1102.
    \18\ ``Support for Cellulosic Determination for Landfill Biogas
and Summary of Lifecycle Analysis Assumptions and Calculations for
Biofuels Produced from Landfill Biogas,'' which has been placed in
docket EPA-HQ-2012-0401.
---------------------------------------------------------------------------

3. Fuel Production--General Considerations
    Landfills currently treat their methane in one of several ways.
Municipal solid waste (MSW) landfills designed to collect at least 2.5
million megagrams (Mg) and 2.5 million cubic meters of waste and
emitting at least 50 Mg of non-methane organic compounds per year are
required by EPA regulations to capture and control their biogas.\19\
These large, regulated landfills represent a small percentage of all
landfills by number but are responsible for the majority of biogas
emissions from landfills. To comply with the regulations, these
landfills must at a minimum combust their biogas in a flare, converting
the methane to carbon dioxide, a less potent GHG. They may also use it
to generate electricity from combustion of the methane, in which case,
the electricity produced may displace electricity from other sources
(such as gas-fired power plants) once it enters the grid. If displacing
other sources of electricity that on average have greater GHG
emissions, landfills that generate electricity may reduce GHG emissions
and are using the ``best practices'' in the industry.\20\ Many smaller,
unregulated landfills do not collect their biogas, and this methane is
``vented'' to the atmosphere. In 2010, 29% of the methane generated at
landfills was flared and 29% of the methane was used to generate
electricity.\21\ Accounting for the 25% average collection efficiency
of biogas collection systems,\22\ we estimate that approximately 38% of
the methane generated is derived from landfills that flare their gas
and another 38% is derived from landfills with gas-to-electricity
projects. By mass balance, this suggests that 24% of the landfill
methane generated is from landfills that vent their methane.
---------------------------------------------------------------------------

    \19\ Standards of Performance for New Stationary Sources and
Guidelines for Control of Existing Sources: Municipal Solid Waste
Landfills, 61 FR 9905, 9944 (March 12, 1996).
    \20\ Some facilities also use the biogas directly in boilers and
other applications or purify the biogas to create CNG or LNG or
inject it directly into natural gas pipelines.
    \21\ Environmental Protection Agency. 2012. Inventory of U.S.
Greenhouse Gas Emissions and Sinks: 1990-2010, Annex 3:
Methodological Descriptions for Additional Source or Sink
Categories. http://epa.gov/climatechange/emissions/usinventoryreport.html. As of December 2012, landfills produced 1913
MW of electricity based on figures from LMOP. This electricity would
be almost entirely sold for use on the grid. From http://www.epa.gov/lmop/projects-candidates/index.html.
    \22\ Environmental Protection Agency, Landfill Methane Outreach
Program. 2010. LFG Energy Project Development Handbook: Chapter 2.
Landfill Gas Modeling. http://epa.gov/lmop/publications-tools/handbook.html.
---------------------------------------------------------------------------

    In our lifecycle GHG analysis of these biofuels we need to consider
what would have happened to the landfill gas if it was not used to
produce transportation fuels. This is the baseline for comparison to
calculate the GHG impacts of the fuels in question. Once we have chosen
a baseline for comparison, we propose to treat biogas from all
landfills the same regardless of how the biogas is processed at that
landfill. This approach is consistent with how we have treated the
implementation of advanced technologies for all biofuels producers.
    For the landfill gas-to-electricity pathway we use landfills that
flare their biogas as the baseline GHG emissions with which we compare
scenarios involving production of electricity from the landfill biogas.
We chose this baseline because these landfills are the ones most likely
to convert to gas-to-energy projects, since they already have gas
collections systems in place. They are also the ones most likely to be
the alternative to gas to energy projects since these projects will
likely go into larger landfills that are required by regulation to
collect and treat the biogas. We expect that small, unregulated
landfills would be unlikely to generate enough biogas to justify
collecting it for conversion to renewable fuels. Furthermore, we expect
that the capital costs for such small landfills would preclude them
from making such changes. However, if such small landfills were to
capture and use their biogas in transportation fuels, this would result
in significantly greater reductions in GHG emissions at each landfill
than assumed for landfills already capturing biogas because of the
decrease in methane release, so that biofuels produced from such
facilities would easily meet the required emissions reduction
thresholds. Since landfills that currently have gas-to-energy projects
in place at one point either replaced flaring with a gas-to-energy
project or installed a gas-to-energy project as an alternative to the
minimal compliance route of flaring, we are proposing to treat the
emissions from these landfills compared to the same flaring baseline.
We show lifecycle results calculated using alternative baselines and
discuss our choice of baseline in more depth in a memo to the

docket.\23\ We invite comment on our baseline assumptions for the
electricity pathway. If commenters believe a different baseline is
appropriate, EPA specifically invites the submission of data supporting
this alternative baseline.
---------------------------------------------------------------------------

    \23\ ``Support for Cellulosic Determination for Landfill Biogas
and Summary of Lifecycle Analysis Assumptions and Calculations for
Biofuels Produced from Landfill Biogas,'' which has been placed in
docket EPA-HQ-2012-0401.
---------------------------------------------------------------------------

    For gas to liquids projects we also use landfills that flare their
biogas as the baseline GHG emissions with which we compare scenarios
involving production of gas to liquids, for the same reasons outlined
above. We further consider that landfills that have already invested
the capital to generate electricity are unlikely to stop doing so in
order to generate liquid fuels from the biogas, which would require
considerable additional capital investments. These facilities are
therefore an unlikely baseline for the pathways generating renewable
diesel and naphtha. We invite comment on our baseline assumptions for
the liquids pathway and whether a different baseline would be more
appropriate. If commenters believe a different baseline is appropriate,
EPA specifically invites the submission of data supporting this
alternative baseline.
4. Fuel Production for Renewable Electricity
    Landfills can generate electricity by combustion of the methane in
their biogas. Generating electricity at landfills requires collection
of the biogas (using wells, piping and blowers), purification and
compression of the biogas and electricity generation. Most landfills
use internal combustion engines to generate the electricity, but a
significant proportion also use gas or steam turbines or combined cycle
systems. Once generated, the electricity enters the electrical grid.
    In determining the lifecycle GHG analysis of renewable electricity,
we examined two main factors. The first involved determining by how
much emissions at the landfill (from flaring) would change upon
installation of a gas-to-energy project. For this calculation, we used
emission factors from the GREET model.\24\ The second involved
calculation of the decrease in GHG emissions caused by powering the gas
blowers already in use with biogas-derived electricity rather than grid
electricity upon installation of a gas-to-energy project. This
calculation used data from the EPA Landfill Methane Outreach Project
(LMOP).\25\ For each factor, we needed to first calculate how much
electricity could be generated and delivered to the consumer. We used
values from LMOP as estimates of the relative shares of different types
of engines or turbines, the electricity generation efficiency,
parasitic losses, energy use in collecting and preparing the biogas,
and a value from the U.S. Energy Information Agency to estimate
distribution losses. Values used are shown in Table V.B.-1, and the
assumptions and calculations are discussed in more detail in a memo to
the docket.\26\
---------------------------------------------------------------------------

    \24\ Argonne National Laboratory (2011) Greenhouse Gases,
Regulated Emissions, and Energy Use in Transportation Model (GREET),
Version 1 2011, http://greet.es.anl.gov/.
    \25\ EPA LMOP Data.
    \26\ ``Support for Cellulosic Determination for Landfill Biogas
and Summary of Lifecycle Analysis Assumptions and Calculations for
Biofuels Produced from Landfill Biogas,'' which has been placed in
docket EPA-HQ-2012-0401.
    \27\ All values are derived from information provided by the EPA
Landfill Methane Outreach Program except the distribution loss
number, which is from the U.S. Energy Information Agency. Parasitic
losses were calculated by apportioning the gross electricity
generation to different types of generators and using parasitic loss
values for that particular type of generator.

   Table V.B.-1--Calculation of the Net Amount of Electricity Delivered to the Consumer Produced From a Given
                                         Amount of Landfill Biogas \27\
----------------------------------------------------------------------------------------------------------------
                                                     Value                            Units
----------------------------------------------------------------------------------------------------------------
Electricity generation efficiency............             11700  Btu/kWh.
Gross electricity production.................             0.292  mmBtu/mmBtu biogas.
Electricity produced after parasitic losses..             0.267  mmBtu/mmBtu biogas.
Energy used for blowers......................             0.014  mmBtu/mmBtu biogas.
Distribution losses..........................             0.017  mmBtu/mmBtu biogas.
Net electricity delivered to consumer........             0.236  mmBtu/mmBtu biogas.
----------------------------------------------------------------------------------------------------------------

    We used the value for the net city yield from biogas to calculate
how GHG emissions from the landfill itself would change upon conversion
from flaring to a gas-to-energy project. We first calculated emissions
per mmBtu electricity (Table V.B.-2). However, the drivetrains of
electric vehicles are roughly three times as efficient as those of
conventional gasoline-powered vehicles, meaning that any given EV would
be able to travel about three times as far per Btu of input. To account
for this difference, we also calculated emissions per mmBtu fuel
equivalent. It would take roughly three times the amount of energy from
liquid fuel to drive a conventional vehicle a given distance compared
to an EV powered by electricity, so the emissions per mmBtu fuel
equivalent are approximately one third as large as the emissions per
mmBtu electricity. EPA invites comments on the assumptions regarding
electricity equivalence.\28\
---------------------------------------------------------------------------

    \28\ Note that in order to determine the number of RINs
generated from a given amount of renewable electricity, section
80.1415(b)(6) of the regulations states that 22.6 kW-hr of
electricity shall represent one gallon of renewable fuel with an
equivalence value of 1.0.

Table V.B.-2--Fuel GHG Emissions for the Renewable Electricity Pathway, Calculated per mmBtu Electricity and per
                          mmBtu Fuel Equivalent Compared to the 2005 Gasoline Baseline
----------------------------------------------------------------------------------------------------------------
                                                                           GHG emissions
                                                 ---------------------------------------------------------------
                                                      Renewable  electricity       2005 Gasoline   U.S. Average
                                                 --------------------------------    baseline          grid
                 Lifecycle stage                                                 ----------------   electricity
                                                    kg CO2-eq/      kg CO2-eq/                   ---------------
                                                       mmBtu        mmBtu fuel      kg CO2-eq/      kg CO2-eq/
                                                    electricity     equivalent      mmBtu  fuel        mmBtu
                                                                                electricity
----------------------------------------------------------------------------------------------------------------
On-site emissions...............................              25               8  ..............  ..............
Upstream (electricity production for blowers)...             -13              -4  ..............  ..............
                                                 ---------------------------------------------------------------
    Total Emissions:............................              12               4              98             220
% Change from Gasoline Baseline.................            -87%            -96%  ..............  ..............
% Change from Grid Electricity..................            -94%             N/A  ..............  ..............
----------------------------------------------------------------------------------------------------------------

    On-site emissions of facilities that generate electricity would be
slightly higher than emissions from facilities that flare because
reciprocating engines, which are the dominant technology used to
generate electricity from biogas, are less efficient at destroying
methane than flares. Facilities that originally flared their biogas are
assumed to have been purchasing electricity from the grid to power the
blowers needed to collect the biogas. Upon conversion to gas-to-energy
projects, the facilities would now generate that electricity themselves
and thus no longer need to purchase this electricity from the grid. The
calculations above include a credit in GHG emissions for the avoided
purchase of grid electricity (Table V.B.-2). Unlike traditional
transportation fuels, there are no GHG emissions involved in
transportation or distribution of renewable electricity (distribution
losses are accounted for above), nor are there any tailpipe emissions
from the direct use of the fuel. Therefore, the only emissions
considered are those from production of the fuel, as outlined in Table
V.B.-2. The total GHG emissions for conversion from flaring to a gas-
to-energy project are 12 kg CO2-eq/mmBtu electricity, or 4
kg CO2-eq/mmBtu fuel equivalent. Compared with the gasoline
baseline GHG emissions of 98 kg CO2-eq/mmBtu, these projects
would be accompanied by an 87% reduction in GHG emissions when
normalized per mmBtu electricity. Accounting for the improved
efficiency of EV drivetrains increases the GHG emissions reductions to
96%. Renewable electricity therefore meets the statutory baseline of
60% reductions in GHG emissions relative to the gasoline baseline and
qualifies as a cellulosic biofuel. EPA invites comments on the
assumptions and calculations of GHG emissions related to renewable
electricity from landfill gas.
5. Fuel Production, Transport and Tailpipe Emissions for Renewable
Diesel and Naphtha
    Renewable diesel and naphtha can be made from landfill biogas by a
combination of methane reforming and the Fischer-Tropsch gas-to-liquids
(GTL) process. For methane reforming, the biogas must first be purified
and then be reformed to create synthesis gas, known as ``syngas,''
which is composed of a mixture of carbon monoxide and hydrogen gas.
This process may occur via either steam methane reforming or
autothermal reforming. The syngas is next purified and then sent to a
Fischer-Tropsch (F-T) system in which the carbon monoxide and hydrogen
are combined in the presence of a catalyst to form a range of
hydrocarbons. This reaction produces relatively short-chain (naphtha),
medium-length (diesel) and long-chain (wax) hydrocarbons. The wax can
subsequently be upgraded by hydroprocessing to form naphtha and diesel
fuels. The different products are then separated by simple
distillation. Heat generated by the reaction can be used to preheat
gases in the system and to generate electricity for use in the system
or for export. Unconverted syngas from the F-T process and fuel gas
from hydroprocessing can also be combusted to generate electricity. GTL
plants may have substantially different lifecycle GHG impacts depending
on whether they upgrade their waxes and whether they generate
electricity as a side product of the reaction. Electricity generation
can add to the capital costs of a facility but also greatly reduces the
lifecycle GHG emissions of a plant.
    In determining the lifecycle GHG impacts of GTL fuels, we
considered two main factors: on-site emissions at the landfill and
upstream emissions from electricity production to power the plant.
Additionally, a facility that produced wax was assigned a co-product
credit for the wax generated. We did the calculations assuming the
facility did not generate any electricity and then calculated what
fraction of their electricity demands they would need to generate
internally to meet the 60% emissions reduction threshold to qualify for
cellulosic RINs.
    To determine the lifecycle GHG emissions, we used confidential
business information (CBI) data provided in a petition submitted to
EPA. This process did not involve upgrading of wax to liquid fuels. For
this scenario, we used the supplied information about inputs of biogas,
outputs of fuel and co-product and electrical demand for the lifecycle
analysis. We first determined how many GHG emissions would be avoided
on-site at the landfill by changing from the baseline scenario of
flaring to collecting the biogas for conversion to liquid fuels. This
calculation was similar to that described above for renewable
electricity and relied on values from GREET \29\ for the emissions
factor for flaring. To calculate the emissions from electricity
required by the process, we used the emissions factors for average U.S.
electrical production used in the RFS2 final rule.
---------------------------------------------------------------------------

    \29\ Argonne National Laboratory, ``Greenhouse Gases, Regulated
Emissions, and Energy Use in Transportation Model (GREET),'' Version
1 2011, http://greet.es.anl.gov/.
---------------------------------------------------------------------------

    To assign a co-product credit to the fuels, we assumed that the wax
produced during the Fischer-Tropsch process would enter a market in
which it would displace wax derived from petroleum. To determine the
effects of such a displacement on GHG emissions, we used data from a
model by the Department of Energy's National Energy Technology
Laboratory (NETL) \30\ for the yields and GHG emissions attributable to
wax production from petroleum

feedstock. These values only include production emissions and do not
include any emissions from combustion of the wax in, for example,
candles because we do not have information about what fraction of wax
is combusted. If combustion emissions were included, the co-product
credit would be even larger. The global wax market is growing, with
demand expected to outpace supply in the next few years.\31\ As such,
it is unlikely that F-T waxes would in reality displace petroleum-
derived waxes. Instead, waxes from both sources are likely to be used
in parallel to fulfill demand, and such waxes would replace any
substitutes that might be used to fill the gap between supply and
demand. The nature of these alternatives is presently unknown to EPA,
as are their lifecycle GHG emissions. As an alternative to assigning a
displacement credit, we could allocate emissions to the waxes along
with the renewable diesel and naphtha products. In this case, the co-
product credit disappears but total fuel production emissions decrease
to 30 kg CO2-eq/mm Btu, leading to overall GHG emissions
reductions of 68%. Our use of the displacement approach is conservative
compared to the allocation approach, which would have resulted in a
larger credit for the wax co-product. We welcome comment regarding what
kinds of materials these new waxes might replace, as well as how to
best account for them in our lifecycle GHG analysis.
---------------------------------------------------------------------------

    \30\ Department of Energy: National Energy Technology
Laboratory. (2009) NETL: Petroleum-Based Fuels Life Cycle Greenhouse
Gas Analysis--2005 Baseline Model. www.netl.doe.gov/energy-analyses.
    \31\ Kline Group (2011) Global Wax Industry 2010: Market
Analysis and Opportunities. http://www.klinegroup.com/reports/brochures/y635a/brochure.pdf.
---------------------------------------------------------------------------

    The results of this analysis are shown on the ``Fuel Production''
line of Table V.B.-3, and the assumptions and calculations are
discussed in more detail in a memo to the docket.\32\ Emissions from
electricity production used to power the F-T plant is the greatest
contributor to the overall fuel production emissions. In addition to
emissions from fuel production, there were minor GHG emissions
attributable to fuel transport and tailpipe emissions of non-
CO2 GHGs (Table V.B.-3). Overall, renewable diesel and
naphtha produced from landfill biogas via this process showed 52% and
51% reductions in GHG emissions, respectively, relative to the diesel
or gasoline baseline (Table V.B.-3). These fuels would therefore
qualify as advanced biofuels but not qualify as cellulosic biofuels.
However, if the facility produced roughly 15% of its process
electricity internally, using either waste heat from the reaction or
combustion of unreacted chemicals, emissions from purchased electricity
would drop enough to reach the 60% GHG reduction threshold, qualifying
these fuels as cellulosic. Because emissions from production of these
biofuels (without internal production of electricity) fall so close to
the 50% threshold to qualify as advanced biofuels, the assumptions used
to make the calculations are especially important and could potentially
change the classification of these fuels. Accordingly, we request
comments about the assumptions and values used in the calculations,
which are detailed in a memo to the docket.\33\ In particular, we
request comment about the estimate for the on-site GHG emissions at the
Fischer-Tropsch facility. Data regarding fugitive emissions from
Fischer-Tropsch facilities using methane as a feedstock appear to be
limited, however, the GREET model assumed a loss factor of 1.0000 for
the production of F-T diesel, indicating their estimate that no methane
is lost during this process. Several studies mentioned emissions from
the steam methane reforming of natural gas to produce hydrogen, and we
assumed emissions would be similar from a Fischer-Tropsch facility
using steam methane reforming. Two of these studies 34 35
found or estimated that losses of methane from such facilities were
negligible, agreeing with the GREET estimate. Accordingly, we assumed
no emissions of methane from F-T facilities. However, another study
\36\ estimated losses of 0.125% of the natural gas processed. Using
this last value, the GHG emissions reductions for renewable diesel and
naphtha would decrease to 49% for both fuels, meaning that the biofuels
would no longer qualify as advanced fuels. We request comments and
information about our estimates of fugitive emissions from Fischer-
Tropsch facilities.
---------------------------------------------------------------------------

    \32\ ``Support for Cellulosic Determination for Landfill Biogas
and Summary of Lifecycle Analysis Assumptions and Calculations for
Biofuels Produced from Landfill Biogas,'' which has been placed in
docket EPA-HQ-2012-0401.
    \33\ ``Support for Cellulosic Determination for Landfill Biogas
and Summary of Lifecycle Analysis Assumptions and Calculations for
Biofuels Produced from Landfill Biogas,'' which has been placed in
docket EPA-HQ-2012-0401.
    \34\ Skone, T.J. and Gerdes, K. (2008) NETL: Development of
Baseline Data and Analysis of Life Cycle Greenhouse Gas Emissions of
Petroleum-Based Fuels. http://www.netl.doe.gov/energy-analyses/pubs/NETL%20LCA%20Petroleum-Based%20Fuels%20Nov%202008.pdf.
    \35\ Spath, P.M. and Mann, M.K. (2001) Lifecycle Assessment of
Hydrogen Production via Natural Gas Steam Reforming. NREL Technical
Report NREL/TP-570-27637, http://www.nrel.gov/docs/fy01osti/27637.pdf.
    \36\ Contadini, J.F., Diniz, C.V., Sperling, D., and Moore, R.M.
(2000) Hydrogen production plants: emissions and thermal efficiency
analysis. ITS-Davis. Presented at the Second International Symposium
on Technological and Environmental Topics in Transports, October 26-
27, 2000. Milan, Italy. Publication No. UCD-ITS-RR-00-16.

Table V.B.-3--Total GHG Emissions for Renewable Diesel and Naphtha Produced From Landfill Biogas and Compared to
                                       the Appropriate Petroleum Baseline
----------------------------------------------------------------------------------------------------------------
                                                                  GHG emissions (kg CO2-eq/mmBtu)
                                                 ---------------------------------------------------------------
                                                             Biofuels                   Petroleum baselines
                 Lifecycle stage                 ---------------------------------------------------------------
                                                     Renewable                      2005 diesel    2005 gasoline
                                                      diesel          Naphtha        baseline        baseline
----------------------------------------------------------------------------------------------------------------
Fuel Production.................................              44              44              18              19
Fuel Transport..................................               1               2               *               *
Tailpipe Emissions..............................               1               2              79              79
                                                 ---------------------------------------------------------------
    Total Emissions.............................              47              48              97              98
% Change from Petroleum Baseline................            -52%            -51%  ..............  ..............
----------------------------------------------------------------------------------------------------------------
* Emissions included in fuel production stage.

    For this lifecycle analysis, we have only examined a facility that
does not upgrade its wax and therefore produces wax as a co-product. It
is likely that other facilities may produce F-T renewable diesel and
naphtha by a

process that does involve upgrading waxes to increase the yield of the
liquid fuels. Accordingly, we used assessments from other analyses of
theoretical F-T \37\ or steam methane reforming \38\ plants using wax
upgrading to estimate the lifecycle GHG emissions from such products.
Based on this analysis (not shown), these facilities should
theoretically have GHG emissions that are as low as or lower than those
calculated above. For this reason, we believe that the lifecycle
analysis shown above is a reasonable, if slightly conservative,\39\
representation of expected landfill biogas-to-liquids projects. We
accordingly classify all renewable diesel and naphtha produced via the
F-T process from landfill biogas as advanced biofuel.
---------------------------------------------------------------------------

    \37\ Swanson, R.M., Satrio, J.A., Brown, R.C., Platon, A., and
Hsu, D.D. (2010) Techno-Economic Analysis of Biofuels Production
Based on Gasification. NREL Technical Report NREL/TP-6A20-46587,
http://www.nrel.gov/docs/fy11osti/46587.pdf.
    \38\ Skone, T.J. and Gerdes, K. (2008) NETL: Development of
Baseline Data and Analysis of Life Cycle Greenhouse Gas Emissions of
Petroleum-Based Fuels. http://www.netl.doe.gov/energy-analyses/pubs/NETL%20LCA%20Petroleum-Based%20Fuels%20Nov%202008.pdf.
    \39\ Emissions estimates are conservatively high.
---------------------------------------------------------------------------

    The lifecycle analysis for these fuels considered that the
renewable diesel product produced from the Fischer-Tropsch process
would be used as conventional diesel fuel. EPA does not have sufficient
information to evaluate the lifecycle greenhouse gas emissions for jet
fuel or heating oil produced from landfill biogas using the Fischer-
Tropsch process. Because the lifecycle analysis results for this
process fell so close to the threshold for advanced biofuels, in this
pathway, we are proposing to only allow renewable diesel for use as
conventional diesel fuel to qualify under the RFS program. We invite
comments and supporting data about whether we should also allow jet
fuel and heating oil produced from landfill biogas to qualify.
    Our lifecycle analysis showed that if the evaluated facility meets
approximately 15% of its electricity demand with internally produced
electricity from eligible sources, it will meet the 60% threshold to
qualify as cellulosic. Because other facilities are likely to be
somewhat different, and because this analysis relies on a number of
assumptions, we are using a slightly more conservative threshold of 20%
of electrical generation. Accordingly, we are proposing that if a
biogas-to-liquids facility produces at least 20 percent of its process
electricity internally as discussed above, these biofuels will qualify
as cellulosic. These requirements are discussed in greater length in
Section C.4. ``Changes Applicable to Process Electricity Production
Requirement for the Biogas- Derived Cellulosic Diesel and Naphtha
Pathways'' below. Facilities that can supply data that demonstrate they
meet the 60% GHG emissions reduction threshold without production of
20% electricity are welcome to petition the EPA individually under
section 80.1416.
    EPA invites comment and data on the GHG emissions associated with
landfill biogas renewable fuel pathways. We also welcome comment on the
methodology and assumptions underlying this analysis. We do not at this
point have sufficient information to evaluate the lifecycle greenhouse
gas emissions for production of renewable electricity or renewable
diesel and naphtha from biogas from waste treatment plants or waste
digesters. Accordingly, we invite comments providing information about
these potential pathways.

C. Proposed Regulatory Amendments Related to Biogas

1. Changes Applicable to the Revised CNG/LNG Pathway From Biogas
    In the existing RFS2 regulations, an approved fuel pathway in Table
1 to section 80.1426(f)(1) allows biogas from landfill gas, manure
digesters or sewage treatment plants to qualify as an advanced biofuel
and generate a D code of 5 for the biofuel produced under the RFS2
program. Since the promulgation of the final rule, we have received
many requests about what fuel qualifies under this pathway, including:
(1) The renewable fuel type that is qualified under the term
``biogas,'' (2) what are the eligible sources of biogas, (3) what
company along the production chain of biogas from generation to end
user is considered the producer that qualifies to register under this
pathway and generate RINs, and (4) what are the contract requirements
to track the biogas from generation to end use.
    In response, EPA is proposing in this rulemaking to amend the
existing biogas pathway in Table 1 to section 80.1426(f) by changing
the renewable fuel type in the pathway from ``biogas'' to ``renewable
compressed natural gas (renewable CNG) and renewable liquefied natural
gas (renewable LNG)'' and to replace the feedstock type of ``landfills,
manure digesters or sewage waste treatment plants'' with ``biogas from
landfills, waste treatment plants or waste digesters.'' We are also
proposing to revise the definition of biogas and add definitions for
CNG and LNG to section 1401 to provide additional clarity. In addition,
we are proposing to revise and add new contracting, registration,
reporting and recordkeeping requirements along the production chain.
Furthermore, we are specifying which company along the production chain
is considered the ``producer'' and eligible to generate RINs under the
RFS2 program. These proposed compliance requirements are applicable to
this revised CNG/LNG pathway, and all the newly proposed pathways for
renewable fuels produced from landfill gas in this rulemaking. The
details of the proposed new requirements for contract, registration,
reporting and recordkeeping are discussed below in the section titled
``Changes Applicable to All Biogas-Related Pathways for RIN
Generation.''
    The existing biogas pathway in Table 1 to section 80.1426(f) refers
to ``biogas'' as the renewable fuel type and ``landfills, manure
digesters and sewage waste treatment plants'' as the feedstock.
Companies have raised questions whether the term ``biogas'' in this
pathway could refer to the unprocessed or raw gas from the landfills,
manure digesters or sewage treatment plants, or processed ``biogas''
that has been upgraded and could be used directly for transportation
fuel or as an ingredient in the production of transportation fuel or as
an energy source used in the production of transportation fuel, or
other fuel types that can be produced from the raw biogas either
through a physical or chemical process (such as CNG, LNG, renewable
electricity, renewable diesel or naphtha). The companies further
inquire if the various forms of biogas discussed above could qualify
under this pathway, and therefore be eligible for RIN generation under
the RFS2 program.
    We agree that the term ``biogas'' in this pathway is used broadly
in the industry to refer to various raw and processed forms of the
biogas from various sources. However, under the existing requirements
in sections 80.1426(f)(10) and (11), only biogas that is used for
transportation fuel can qualify as renewable fuel for RIN generation
under the RFS2 program. We believe the stipulations in sections
80.1426(f)(10) and (11) are clear that biogas used for non-
transportation fuel purposes, such as an energy source for providing
process heat would not qualify under this biogas pathway for RIN
generation. Similarly, raw biogas would also not qualify under this
pathway since unprocessed biogas cannot be used as transportation fuel.
With regard to the fuel types that can be

produced from the raw biogas such as CNG, LNG, renewable electricity,
renewable diesel, or naphtha, the pathway determinations for the final
rule did not account for all factors relevant for the additional fuel
types such as renewable electricity, renewable diesel or naphtha
produced from the raw biogas through a chemical process. Therefore,
renewable electricity, renewable diesel and naphtha produced from
biogas do not qualify under the existing pathway.\40\ For CNG and LNG,
we concluded that these types of fuels were close enough to the
physical molecules of biogas since these fuels only go through a
physical process in which the biogas is compressed or liquefied, and
that because CNG and LNG can be used directly for transportation
purposes, thus meeting the provisions in sections 80.1426(f)(10) and
(11), we concluded that CNG and LNG could qualify under the existing
pathway. For the reasons discussed above, we are proposing to amend the
existing biogas pathway to clearly state that only CNG and LNG produced
from biogas from landfills, waste treatment plants and waste digesters,
and used as transportation fuel, qualify as a cellulosic or advanced
biofuel for RIN generation under the RFS2 program.
---------------------------------------------------------------------------

    \40\ For this rulemaking, we conducted lifecycle analysis for
renewable electricity, renewable diesel, naphtha produced from
landfill gas, and are proposing new fuel pathways to Table 1 to
Section 80.1426 for these fuel types. Please see section titled,
``Lifecycle Greenhouse Gas Emissions Analysis for Renewable
Electricity, Renewable Diesel and Naphtha Produced from Landfill
Biogas'' for the lifecycle analysis discussion in this rulemaking.
---------------------------------------------------------------------------

    The current regulations provide a pathway for biogas produced from
a bio-digester which uses manure. We are also proposing to expand the
type of materials that may be used to produce CNG/LNG in a digester to
include animal wastes, biogenic waste oils/fats/greases, separated food
and yard wastes, and crop residues. These feedstock sources are already
eligible in the existing rules pathways and therefore should reasonably
be added to the bio-digester pathway. We are doing so in response to a
petition request to generate RINs from biogas which is produced from
bio-feedstock sources in addition to the already allowed manure, either
individually or in combination with manure in a bio-digester. As with
other LCA pathways using these materials, EPA is proposing to assume
these waste materials do not have emissions associated with feedstock
production, and therefore qualify as cellulosic or advanced renewable
fuels when used to produce CNG/LNG.
    To provide improvement for this revised pathway, we are proposing
to revise the definition of biogas and add new definitions for
renewable CNG and renewable LNG to section 80.1401 to read as follows:

    We are proposing Biogas would mean a mixture of hydrocarbons
that is a gas at 60 degrees Fahrenheit and 1 atmosphere of pressure
that is produced through the conversion of organic matter. We are
also proposing that Biogas would include landfill gas, gas from
waste digesters, and gas from waste treatment plants. Waste
digesters would include digesters processing animal wastes, biogenic
waste oils/fats/greases, separated food and yard wastes, and crop
residues. Waste treatment plants would include wastewater treatment
plants and publicly owned treatment works.
    We are proposing that Renewable compressed natural gas
(``renewable CNG'') would mean biogas that is processed to the
standards of pipeline natural gas as defined in 40 CFR 72.2 and that
is compressed to pressures up to 3600 psi. We are also proposing
that only renewable CNG that qualifies as renewable fuel and is used
for transportation fuel can generate RINs.
    We are proposing that Renewable liquefied natural gas
(``renewable LNG'') would mean biogas that is processed to the
standards of pipeline natural gas as defined in 40 CFR 72.2 and that
goes through the process of liquefaction in which the biogas is
cooled below its boiling point and weighs less than half the weight
of water so it will float if spilled on water. We are also proposing
that only renewable LNG that qualifies as renewable fuel and is used
for transportation fuel can generate RINs.
2. New Registration (Contract Requirements) for Renewable Electricity
and Fuels Produced From Biogas That Qualify as Renewable Fuel and That
Are Registered for RIN Generation
    The regulations as currently written allow a producer of biogas or
renewable electricity \41\ that qualifies as renewable fuel and has an
approved fuel pathway in Table 1 of section 1426(f)(1) to register and
generate RINs for the volume it produces under the RFS2 program. We
modified the existing regulations to state that biogas is the feedstock
used to produce renewable fuel, as described above. The revised
regulations in sections 1426(f)(10) and (11) detail the requirements
for distribution and tracking for renewable electricity and biogas used
to produce fuel that qualifies as renewable fuel that can either be
distributed in a dedicated pipeline or transmission line or distributed
in a shared pipeline or power grid system. The purpose of these
requirements is to provide EPA assurance and verification that once the
biogas or renewable electricity is put into a dedicated or shared
distribution system that in fact an equivalent volume of biogas or
renewable electricity will be used for transportation fuel, and for no
other purposes. The requirements are also meant to address concerns of
double counting of the biogas or renewable electricity, especially in
situations that the biogas or renewable electricity is placed in or
loaded onto shared distribution systems that contain gas or electricity
from non-renewable biomass sources. EPA intended to require producers
to submit the information and contract requirements in sections
1426(f)(10) and (11) as part of the registration requirements for
renewable electricity and renewable fuels produced from biogas that are
used for transportation \42\ fuel, but had not done so in the prior
rulemakings. Therefore, as a natural outgrowth of the regulations for
implementation and compliance purposes, we are proposing in this
rulemaking to incorporate the requirements in sections 1426(f)(10) and
(11) as part of registration requirements for producers of renewable
electricity and renewable fuels produced from biogas that qualify as
renewable fuel under the regulations under section 1450(b)(1)(iv)(C).
---------------------------------------------------------------------------

    \41\ EPA notes that currently, producers of renewable
electricity that may qualify as a renewable fuel cannot register and
generate RINs because there is no approved pathway in Table 1 for
renewable electricity from any approved feedstock. But in the event
that an approved pathway for renewable electricity is added to Table
1, EPA notes there are existing requirements such as tracking and
distribution requirements recordkeeping and reporting that are
applicable for the registration of renewable electricity for RIN
generation.
    \42\ Distribution and registration requirements for biogas used
as process heat, and not for RIN generation as renewable fuel is
detailed in Section 1426(f)(12) and 1450(b)(1)(iv), respectively.
---------------------------------------------------------------------------

    Section 1426(f)(11)(ii) of the regulations requires that, in order
for renewable fuel made from biogas withdrawn from a commercial
distribution system for use as a transportation fuel to generate RINs,
the biogas introduced into the system must have been added to a common
carrier pipeline. We propose to add a similar provision to section
1426(f)(11)(i) for renewable electricity, requiring a company to load
the renewable electricity to a power grid shared by the second company
that withdraws the electricity, such that the two companies must be
physically connected to the same grid or located within the same area.
    EPA is requesting comments about whether the other existing
requirements in sections 1426(f)(10) and (11) for renewable electricity
and renewable fuels from biogas used for transportation

fuel are sufficient to provide assurance and verification for the
following situations. First, do the proposed requirements provide
assurance and verification that the same amount of biogas or renewable
electricity is in fact delivered to the renewable fuel producer or end
user who will actually use the biogas or renewable electricity for
transportation purposes? If the proposed requirements are not
sufficient, what alternative requirements should be considered? Second,
are the proposed requirements sufficient to ensure that double counting
does not occur, e.g., to ensure that the biogas or renewable
electricity once it is loaded into a shared pipeline or power grid is
not sold to multiple clients or for purposes other than for
transportation purposes? Similarly, if the proposed requirements are
not sufficient, what alternative requirements could be considered to
ensure double counting does not occur?
3. Changes Applicable to All Biogas Related Pathways for RIN Generation
    As discussed above, we have had many inquiries related to the
``biogas'' pathway, specifically regarding contract requirements for
tracking the biogas through the distribution system and regarding what
company along the production chain is considered the ``producer'' and
eligible to generate RINs under the RFS2 program. In this rulemaking,
we are proposing to revise and add new requirements for contracts to
track the biogas as it moves into and out of the distribution system,
as well as provisions on registration, reporting and recordkeeping.
These proposed amended requirements are applicable to all pathways
related to biogas that are eligible for RIN generation that are
existing or proposed in this rulemaking.
    In response to the question of what company is considered the
producer of renewable fuel and eligible to generate RINs under the RFS
program, we propose to clarify who is the ``producer'' for renewable
CNG/LNG and renewable electricity. We propose that the ``producer'' of
renewable CNG/LNG is the company that compresses or liquefies the gas
and distributes the CNG/LNG for transportation fuel, and for renewable
electricity, the ``producer'' is the company that distributes the
electricity for use as transportation fuel. There are two registration
situations that this clarification will address: (1) The owner/operator
of a landfill collects biogas and processes it to a qualifying
renewable CNG/LNG/electricity for transportation use and distributes on
site and (2) the owner/operator of a landfill collects biogas and it is
processed into a qualifying renewable CNG/LNG/electricity for
transportation use by a contracted third party and distributed by this
third party. The party that converts the biogas to renewable CNG/LNG/
electricity and distributes for use as a transportation fuel is
responsible for RIN generation. Under the first scenario, the
registration package, including the engineering review, would cover the
biogas source (landfill, waste digester, etc.) as well as the
distribution that is occurring on site. Under the the second scenario,
the registration package, including engineering review, would cover the
biogas source (landfill, waste digester, etc.) the pipeline (common
carrier or dedicated) and each distribution facility. By requiring the
party that is responsible for conversion and distribution to register
as the RIN generator, we can prevent RINs from being generated for a
batch or renewable CNG/LNG/electricity prior to use as a qualifying
transportation fuel. For any of the fuels, the company designated as
the ``producer'' will be required to register under the RFS2 program.
We seek comment on our proposed definition of producer regarding
renewable CNG/LNG and renewable electricity.
    We acknowledge that the process train from raw biogas to the final
transportation fuel is complex, and may include many companies and
processing steps from the point when the raw biogas is withdrawn from
its source (such as landfills, waste digesters, waste treatment
plants), processed and converted into biofuel and distributed to
consumers. Alternatively, the fuel may be cleaned at a biogas facility
to pipeline quality specifications for distribution, and then withdrawn
from the commercial pipeline to be processed further at another
production facility into renewable CNG/LNG or renewable electricity.
Due to the complexity of the many entities potentially involved in this
process train, we are proposing that the company deemed as the
``producer'' under the qualifications described above also be
responsible for providing all the required information and supporting
documentation in their registration, reporting and recordkeeping to
track and verify the information from point of extraction of the raw
biogas from its original source, and all the processing steps and
distribution in between, to the last step where the actual fuel is used
for transportation purposes. In the engineering review report required
for registration, the producer must include documentation that the
professional engineer performed site visits at each production
facility, including the biogas facility and the facility that produces
the final fuel (if these are not the same facility). The producer must
also review and verify all related supporting documents such as design
documents, calculations, regulatory permits, and contracts between
facilities that track the raw biogas from the point of withdrawal from
its source, the various injection/withdraw points into the distribution
pipeline, the various production facilities, and the final step for use
as transportation fuel. We believe these requirements will ensure that
producers will perform due diligence that the fuel for which they
generate RINs under the RFS2 program are in compliance with all the
regulatory requirements for renewable fuel. The proposed registration,
reporting and recordkeeping requirements are in sections 80.1426(f),
80.1450, 80.1451 and 80.1454 in this rulemaking. Additional changes
regarding the contract requirements for distribution of the biogas in
shared commercial pipelines are discussed below, and can be located in
sections 80.1426(f)(10), (11), and (13).
4. Changes Applicable To Process Electricity Production Requirement for
the Biogas-Derived Cellulosic Diesel and Naphtha Pathways
    In this proposed rulemaking, EPA conducted greenhouse gas (GHG)
lifecycle analysis for various renewable fuels produced from landfill
gas as new or revised advanced and cellulosic biofuel pathways that
will be added to Table 1 to section 80.1426(f).\43\ For some of these
pathways, we are proposing to add various registration, recordkeeping
and reporting requirements to the regulations to ensure that the
facilities using these pathways meet the parameters stipulated in the
lifecycle analysis. The additional registration, recordkeeping and
reporting requirements are discussed in detail below.
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    \43\ Refer to preamble discussion for these various biogas
pathways in section titled, ``Lifecycle Greenhouse Gas Emissions
Analysis for Renewable Electricity, Renewable Diesel and Naphtha
Produced from Landfill Biogas.''
---------------------------------------------------------------------------

    For the proposed fuel pathways for cellulosic diesel and cellulosic
naphtha produced from landfill gas, we are proposing to require the
renewable fuel production facility to produce a minimum of 20 percent
of the process electricity used at the facility on a calendar year
basis, from raw landfill gas, waste heat from the production process,
unconverted syngas from the

F-T process, fuel gas from the hydroprocessing or combined heat and
power (CHP) units that use non-fossil fuel based gas or other renewable
sources. We propose that if less than 20 percent (on an annual average
basis) of process energy comes from one of these alternative sources,
then no cellulosic RINs can be generated for that year.
    For the renewable fuel production facility applying to use the
proposed fuel pathway with the requirement to internally produce at
least 20 percent of the total amount of process electricity used at its
facility, we are proposing the facility submit to EPA the information
described below to demonstrate compliance with this requirement. For
registration purposes, we are proposing that producers submit the
following additional information in the process fuel supply plan that
is currently required as part of the registration process (estimated
summaries are to be reported on an annual/calendar year basis):

--Estimated amount of total electricity used at the facility
--Estimated amount of total electricity purchased for the facility
--Estimated amount of total renewable electricity produced on-site,
including the source of the energy and the equipment and/or process
used to generate the renewable electricity
--Calculation that verifies the facility meets the specified 20 percent
minimum electricity production requirement based on the reported total
amount of electricity used at the facility, total amount of electricity
purchased, and total amount of renewable electricity produced

    For reporting purposes, we are proposing for producers to submit
the following additional information as part of their existing
quarterly and annual reporting obligations (reported amounts should be
provided as monthly summaries on an annual/calendar year basis, and
must be obtained from a utility meter that is continuously measured):

--Actual total amount of electricity used at the facility
--Actual total amount of electricity purchased for the facility
--Actual amount of total renewable electricity produced on-site,
including source of energy and the equipment or process used to
generate the renewable electricity
--Calculation that verifies the facility meets the specified 20 percent
minimum electricity production requirement based on the reported total
amount of electricity used at the facility, total amount of fossil-fuel
based electricity purchased, and total amount of renewable electricity
produced

    For recordkeeping purposes, we are proposing that producers retain
the additional information, calculations and supporting documents
required for registration and reporting as discussed above. The
regulatory requirements for registration, reporting and recordkeeping
as discussed in this proposed rulemaking can be located in the
following applicable regulatory sections 80.1450, 80.1451 and 80.1454,
respectively.

D. Amendment to the Definition of ``Crop Residue'' and Definition of a
Pathway for Corn Kernel Fiber

    We propose to amend the definition of ``crop residue'' so that this
category includes only feedstock sources that are determined by EPA
would not result in a significant increase in direct or indirect GHG
emissions. ``Crop residue'' is 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. Biomass
is considered crop residue only if the use of that biomass for the
production of renewable fuel has no significant impact on demand for
the feedstock crop, products produced from that feedstock crop, and all
substitutes for the crop and its products including the residue, nor
any other impact that would result in a significant increase in direct
or indirect GHG emissions.
    EPA is amending the definition of ``crop residue'' to confirm the
meaning of the term ``left over'' in the text of this definition. The
phrase ``left over'' in our original definition of ``crop residue'' is
meant to indicate that the use of a residue as a biofuel feedstock
should not increase demand for the crop it is derived from, should not
induce further crop production, and should not result in additional
direct or indirect GHG emissions. The residue must come from crop
production or processing for some other primary purpose (e.g., refined
sugar, corn starch ethanol), such that the crop residue is not the
reason the crop was planted. The residue must also come from existing
agricultural land, the exact definition of which is laid out in our
current regulations that define ``renewable biomass''.\44\ Further, the
residue should generally not have a significant market in its own
right, to the extent that removing it from that market to produce
biofuels instead will result in increased GHG emissions. EPA is seeking
comments on this revision to the crop residue definition. EPA invites
all comments regarding this revision, but specifically invites comments
regarding the potential for the revision to create a significant shift
in direct or indirect GHG emissions and what ought to constitute a
``significant'' increase or decrease in GHG emissions in the context of
this definition.
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    \44\ See specifically Sec.  80.1401 Definitions.
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    EPA has previously identified several potential feedstocks that we
believe meet the criteria of crop residue. Table IV.D.-1 lists
feedstocks which may fit the definition of crop residue. Most of these
feedstocks were discussed in the final RFS2 rulemaking. For example,
EPA analyzed the agricultural sector GHG emissions of using corn stover
for biofuels in the final RFS2, and found that fuel produced from this
feedstock met the 60% GHG reduction threshold for cellulosic biofuels.
Since the direct and indirect impacts of citrus residue, rice straw,
and wheat straw removal were expected to be similar to corn stover, EPA
also applied the land use change impacts associated with corn stover to
citrus residue, rice straw, and wheat straw. Based on that analysis,
EPA found that fuels produced from citrus residues, rice straw, and
wheat straw also met the 60% reduction threshold. EPA further
determined that fuels produced from materials left over after the
processing of a crop into a useable resource had land use impacts
sufficiently similar to agricultural residues to also meet the 60%
threshold. EPA specifically cited bagasse left over from sugarcane
processing as an example of this type of residue. EPA is seeking
comment on whether the feedstocks on this list should be considered
crop residues, if these feedstocks would have similar direct and
indirect impacts as corn stover, and whether additional feedstocks
should also be included in this list.

       Table IV.D.-1--Feedstocks That May Qualify as Crop Residue
------------------------------------------------------------------------
             Feedstock                              D Code
------------------------------------------------------------------------
Sugarcane Bagasse..................  D-3 Cellulosic biofuel.
Corn Kernel Fiber (excluding the     D-3 Cellulosic biofuel.
 corn starch component).

Corn Stover........................  D-3 Cellulosic biofuel.
Citrus Residue.....................  D-3 Cellulosic biofuel.
Rice Straw.........................  D-3 Cellulosic biofuel.
Wheat Straw........................  D-3 Cellulosic biofuel.
------------------------------------------------------------------------

    While EPA believes that, under current conditions, generation of
RINs for batches of renewable fuel produced from the feedstocks listed
in Table IV.D.-1 above would not result in a significant increase in
direct or indirect GHG emissions, we also acknowledge the potential for
this assessment to change in the future based on unforeseeable factors.
For example, some new use for one of these products could be developed
which would change our assessment that the feedstock has no significant
market in its own right. Further, it is possible that, at some point in
the future, large enough quantities of renewable fuel could be produced
from one of these fuels to create demand pull for the feedstock,
potentially altering the behavior of producers of the residue and
leading to significant increases in direct or indirect GHG emissions.
To our knowledge, this is not currently the case for any of the
feedstocks listed above. However, EPA will continue to monitor RIN
generation from fuel produced using each of these feedstocks and the
general use of these feedstocks in the marketplace. We further reserve
the right to revisit the status of any feedstock that we have
determined qualifies under the crop residue pathway. Should any
feedstock qualifying as a crop residue be used to generate significant
quantities of ethanol in the future, or should a significant market
emerge for the product such that there is demand pull for it in excess
of the demand pull for the planted crop from which it is a derived
byproduct, we will revisit whether that feedstock should remain under
the crop residue pathway or be subjected to further scrutiny. EPA is
seeking comment on this approach and on the potential for significant
demand pull to emerge for the feedstocks we are proposing to consider
as crop residues.
    We also propose that this definition of ``crop residue'' includes
corn kernel fiber. Corn kernel fiber is not specifically mentioned as a
type of crop residue under the Renewable Fuel Standard (RFS2)
regulations. Per the RFS2 definition of ``crop residue'', EPA must
evaluate whether corn kernel fiber is ``left over from the harvesting
or processing of planted crops'' and that it has no ``impact that would
result in a significant increase in direct or indirect GHG emissions''
for this feedstock to qualify as a residue.
    One additional consideration in the classification of corn kernel
as a crop residue is the fact that some amount of corn starch might
still adhere to the corn kernel after separation. The percentage of
contamination will vary, but as much as 20% of the final fuel could be
derived from corn starch. By definition, corn starch ethanol can only
qualify as a renewable fuel, not as an advanced fuel. However, our
current regulations state that ``producers and importers may disregard
any incidental, de minimis feedstock contaminants that are impractical
to remove and are related to customary feedstock production and
transport''.\45\ Therefore, EPA is seeking comment on whether the
definition of crop residue should be amended to explicitly exclude the
corn starch component.
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    \45\ See specifically Sec.  80.1426(f)(1).
---------------------------------------------------------------------------

    EPA also invites comment on how RINs should be allocated for
ethanol derived from corn fiber. EPA has existing regulations that
define procedures for generating RINs from batches of fuel that contain
multiple feedstocks, including feedstocks that generate RINs of
different D codes.\46\ We believe that these regulations provide
sufficient guidance to producers and importers regarding how to assign
RINs to batches of renewable fuel that can be described by two or more
pathways (e.g., corn starch ethanol and corn kernel fiber ethanol).
However, we invite comment on the sufficiency of these regulations with
regards to the assignment of RINs to coprocessed batches of corn starch
ethanol and corn kernel fiber ethanol, including whether producers have
the technological capability to adequately demonstrate volume produced
under each pathway.
---------------------------------------------------------------------------

    \46\ See specifically Sec.  80.1426(f)(3).
---------------------------------------------------------------------------

    To determine whether the use of corn kernel fiber to produce
ethanol would lead to increased direct or indirect GHG emissions, EPA
conducted a detailed assessment of the two major potential sources of
emissions from this feedstock, namely effects on feed markets and
effects on demand for corn. The proposed method of acquiring corn
kernel fiber is to extract it from matter that is otherwise converted
to dried distillers grains (DDG) during the dry mill corn ethanol
process. Consequently, this analysis relied significantly on the
assessment of corn starch ethanol-derived DDG that was conducted for
the RFS2 final rule, adjusting the analysis to account for the
extraction of fiber from this product. The analysis also drew
substantially on the available scientific literature on low fiber DDG
(LF-DDG), as well as the expertise of the U.S. Department of
Agriculture. Potential producers also submitted important data to EPA
that helped determine whether producing cellulosic ethanol from corn
kernel fiber would result in a significant increase in GHG emissions.
This included a full nutritional analysis of LF-DDG for swine, poultry,
and cattle.
    EPA found that extracting the fiber from corn matter used to
produce standard DDG would not have a significant effect on feed
markets. Processors who extract the fiber from corn produce a feed
product known as LF-DDG, as opposed to standard DDG which retains the
fiber. The scientific literature on LF-DDG animal nutrition has found
that this product has at least equal, and perhaps even slightly
superior, nutritional value for swine and poultry compared to standard
DDG.\47\ This means that, even though the physical volume of the DDG
produced by ethanol plants using corn kernel fiber extraction
technology will be somewhat smaller, its nutritional content for swine
and poultry will be equivalent to or greater than their output without
fiber extraction.
---------------------------------------------------------------------------

    \47\ See, e.g., Kim, E.J., C.M. Parsons, R. Srinivasan, and V.
Singh. 2010. Nutritional composition, nitrogen-corrected true
metabolizable energy, and amino acid digestibilities of new corn
distillers dried grains with solubles produced by new fractionation
processes. Poultry Science 89, p. 44, available on the docket for
this rulemaking. See also additional studies cited within Kim et al
2010.
---------------------------------------------------------------------------

    Conversely, LF-DDF is an inferior feed for cattle compared to
standard DDG, since ruminants benefit from ingesting corn fiber in
DDG.\48\ Therefore, EPA expects swine and poultry producers to absorb
the supply of LF-DDG, while the cattle and dairy industry will continue
to consume standard DDG. With this dynamic in place, fiber extraction
from DDG should not significantly affect feed markets, since there will
be no reduction in the overall supply of DDG in terms of nutritional
content nor will there be any impact on aggregate demand for other
animal feed sources.
---------------------------------------------------------------------------

    \48\ See Shurson, G.C. 2006. The Value of High-Protein
Distillers Coproducts in Swine Feeds. Distillers Grains Quarterly,
First Quarter, p. 22, available on the docket for this rulemaking.
---------------------------------------------------------------------------

    If enough corn ethanol producers adopt fiber extraction technology,
LF-DDG could saturate swine and poultry demand and spill over into
dairy and cattle feed markets. If a situation arises where LF-DDG begin
to replace standard DDG in cattle markets, this could lead to an
increase in feed

demand, most likely in the form of increased demand for fiber
supplements in dairy and cattle feed. This could cause an increase in
GHG emissions. If swine and poultry demand for LF-DDG becomes
saturated, demand for standard DDG in the cattle and dairy industries
should create sufficient market incentives for the remaining corn
starch ethanol producers to decide against adopting corn fiber ethanol
production. EPA believes this will prevent a situation where there is
insufficient supply of standard DDG in the cattle and dairy industries.
However, as noted above, EPA reserves the right to reexamine corn
kernel fiber as a feedstock in the future.
    EPA's analysis indicates that producing cellulosic ethanol from
corn kernel fiber is unlikely to increase overall demand for corn. In
order to meet the definition of a crop residue, the source of corn
kernel fiber must be a crop processing facility (e.g., a corn starch
ethanol plant). A corn kernel fiber ethanol producer cannot purchase
whole corn specifically for the generation of corn fiber ethanol and
still qualify their feedstock as crop residue. EPA is seeking comment
on this analysis.
    Based on our assessment, EPA proposes that corn kernel fiber would
meet the definition of a crop residue, and qualify for Cellulosic
Ethanol and Advanced Biofuel (D-codes 3 & 5, respectively) RINs under
the RFS2. EPA is seeking comment on whether corn kernel fiber should be
considered a crop residue.

E. Consideration of Advanced Butanol Pathway

1. Proposed New Pathway
    EPA is proposing to add a new pathway to Table 1 to section 80.1426
that allows butanol made from corn starch using a combination of
advanced technologies to meet the 50% GHG emissions reduction needed to
qualify as an advanced renewable fuel. This pathway applies to dry mill
fermentation facilities that use natural gas and biogas from an on-site