
[Federal Register Volume 78, Number 115 (Friday, June 14, 2013)]
[Proposed Rules]
[Pages 36041-36078]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2013-12714]



[[Page 36041]]

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  

[[Page 36042]]


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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: a-and-r-docket@epa.gov, 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 (202) 566-1744, and the 
telephone number for the Air and Radiation Docket is (202) 566-1742.

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: (202) 343-9034; fax number: (202) 343-2801; email address: 
sopata.joe@epa.gov.

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

[[Page 36043]]

    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

[[Page 36044]]

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

[[Page 36045]]

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\
------------------------------------------------------------------------
                                                       Average  adjusted
                                                           cellulosic
                    Feedstock type                        composition
                                                           (percent)
------------------------------------------------------------------------
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.
---------------------------------------------------------------------------

    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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[[Page 36046]]

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

[[Page 36047]]

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

[[Page 36048]]

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

[[Page 36049]]

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

[[Page 36050]]

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\
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    \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.

[[Page 36051]]



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

[[Page 36052]]

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

[[Page 36053]]

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

[[Page 36054]]

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

[[Page 36055]]

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

    \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

[[Page 36056]]

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

    \44\ See specifically Sec.  80.1401 Definitions.
---------------------------------------------------------------------------

    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).

[[Page 36057]]

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

    \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

[[Page 36058]]

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 
thin stillage anaerobic digester for process energy with combined heat 
and power (CHP) producing excess electricity of at least 40% of the 
purchased natural gas energy of the facility (the proposed ``advanced 
butanol pathway'').
    GEVO Incorporated submitted a petition requesting authorization to 
generate D-code 5 RINs for fuel produced through the GEVO butanol 
pathway. A petition is required because the proposed process utilizes a 
high yield butanol fermentation process that is different from those 
analyzed as part of the RFS2 corn ethanol pathways, and does not use 
the approved advanced technologies shown in Table 2 to section 80.1426 
of the RFS2 regulations.
    EPA's evaluation of the lifecycle GHG emissions of the advanced 
butanol pathway under this petition request is consistent with EISA's 
applicable requirements, including the definition of lifecycle GHG 
emissions and threshold evaluation requirements. It was based on 
information regarding GEVO's production process that was submitted 
under a claim of Confidential Business Information (CBI) by GEVO on 
April 11, 2011. The information provided included the mass and energy 
balances necessary for EPA to evaluate the lifecycle GHG emissions of 
the advanced butanol pathway.
    The lifecycle GHG emissions of fuel produced pursuant to the 
advanced butanol pathway were determined as follows:
    Feedstock production--The advanced butanol pathway uses corn starch 
as a feedstock. Corn starch is one of the feedstocks already listed in 
Table 1 to section 80.1426 of the RFS2 regulations. Since corn starch 
has already been evaluated as part of the RFS2 final rule, no new 
feedstock production modeling was required.
    The FASOM and FAPRI models were used to analyze the GHG impacts of 
the feedstock production portion of the fuel's lifecycle. The same 
FASOM and FAPRI results representing the emissions from an increase in 
corn production that were generated as part of the RFS2 final rule 
analysis of the existing corn butanol pathways were used in this 
analysis of the advanced butanol pathway. These results represent 
agriculture/feedstock production emissions for a certain quantity of 
corn produced. For the RFS2 analysis, this was roughly 960 million 
bushels of corn used to produce 2.6 billion gallons of fuel. We have 
calculated GHG emissions from feedstock production for that amount of 
corn. EPA does not believe the advanced butanol process for converting 
corn into butanol will materially affect the total amount of corn used 
for biofuels and modeled as part of the RFS2 final rule. Based on 
information provided by industry, the technologies to produce corn 
butanol are primarily being targeted at retrofitting existing corn 
ethanol facilities, where the infrastructure to produce renewable fuels 
already exists and the capital expenditures would be relatively small. 
Therefore, the existing agricultural sector modeling analyses for corn 
as a feedstock remain valid for use in estimating the lifecycle impact 
of renewable fuel produced using the advanced butanol pathway. The 
Agency is seeking comment on whether there is any research to suggest 
that converting corn into an advanced butanol pathway would materially 
affect the total amount of corn used.
    GEVO provided, as part of the information claimed CBI, their 
process yield in terms of gallons of fuel produced per bushel of corn. 
Based on the data, GEVO's process yield is slightly more efficient than 
the pathways modeled as part of the RFS2 rulemaking. Therefore, 
compared to the corn butanol pathways already analyzed, the GEVO 
process results in 0.93% more Btus of fuel produced for the same amount 
of corn feedstock.
    Fuel production--The fuel production method included in this 
advanced butanol pathway involves the production of butanol from corn 
starch in a dry mill. The amount and type of energy used in this 
analysis is different than production methods that were analyzed under 
the final rule. While there were slight differences in the total amount 
of natural gas and electricity used in this analysis, the main 
difference was the use of biogas and production of excess electricity. 
To analyze the GHG impacts of the advanced butanol pathway, EPA 
utilized the same approach that was used to determine the impacts of 
processes in the RFS2 corn butanol pathways.
    The amount and type of energy used was taken from GEVO's mass 
balance & energy balance submitted to EPA. GEVO submitted energy data 
on natural gas and biogas (in Btus) and electricity (in kWhs) inputs, 
as well as gallons of fuel produced. Biogas and natural gas are used in 
combination, while the RFS2 corn butanol analyses only considered 
natural gas or biogas used independently, not in combination.
    The emissions from the use of energy were calculated by multiplying 
the amount of energy by emission factors for fuel production and 
combustion, based on the same method and factors used in the RFS2 final 
rulemaking. The emission factors for the different fuel types are from 
GREET and were based on assumed carbon contents of the different 
process fuels.
    One area where EPA is soliciting comments is on the most 
appropriate energy content assumption to use for butanol (lower heating 
value). As part of this analysis, EPA used the GREET value for the 
energy content of butanol,

[[Page 36059]]

which is 99,837 Btus per gallon.\49\ Differences in the measurement of 
the energy content of butanol can occur for a number of reasons 
including variations amongst isomers (t-butanol, n-butanol, isobutanol, 
and sec-butanol), and differences in testing methodologies. EPA is 
seeking comment on whether there are any reasons why EPA should change 
its assumptions and use a different energy content of butanol.
---------------------------------------------------------------------------

    \49\ The GREET value is based on: Guibet, J.-C., 1997, 
Carburants et Moteurs: Technologies, Energie, Environnement, 
Publication de l'Institut Fran[ccedil]ais du P[eacute]trole, ISBN 2-
7108-0704-1.
---------------------------------------------------------------------------

    The RFS2 corn butanol pathways included an estimate for DDGs co-
product production which we similarly applied to the advanced butanol 
production process. Since DDGs impact the agricultural markets, 
production of DDGs was already included as part of the FASOM and FAPRI 
modeling already described in the feedstock production section, above. 
Thus no additional co-product credits for the DDGs are applied for the 
fuel production stage of the analysis.
    The advanced butanol production process analyzed here also results 
in excess electricity production. As per the pathway description the 
process produces excess electricity of at least 40% of the purchased 
natural gas energy of the facility. The onsite emissions of the 
electricity production are accounted for in the facility natural gas 
and biogas use. The co-product credit of the excess electricity is 
accounted for by assuming the electricity offsets average grid 
electricity production and results in associated emission reductions.
    The estimated production emissions from the advanced butanol 
process are shown below in Table V.F.-1.

Table V.F.-1--Fuel Production Emissions for the Advanced Butanol Process
------------------------------------------------------------------------
                                                 GEVO isobutanol  (g CO2-
             Fuel production source                     eq./mmBtu)
------------------------------------------------------------------------
On-Site Emissions..............................                   15,273
Upstream (natural gas and electricity                              2,424
 production)...................................
Emissions Credit from Offset Electricity.......                  -17,448
                                                ------------------------
  Total Fuel Production Emissions..............                      249
------------------------------------------------------------------------

    Fuel and feedstock distribution--We used the same feedstock 
distribution emissions assumption considered for corn butanol under the 
RFS2 final rule for the advanced butanol pathway corn feedstock. The 
fuel type, butanol, and hence the fuel distribution for butanol, was 
already considered as part of the RFS2 final rule. Therefore, the 
existing feedstock and fuel distribution lifecycle GHG impacts for corn 
butanol were applied to the advanced butanol pathway analysis.
    Use of the fuel--The advanced butanol pathway produces a fuel that 
was analyzed as part of the RFS2 final rule. Thus, the fuel combustion 
emissions calculated as part of the RFS2 final rule for butanol were 
applied to our analysis of the advanced butanol pathway.
    The advanced butanol fuel was then compared to baseline petroleum 
gasoline, using the same value for baseline gasoline as in the RFS2 
final rule analysis. The results of the analysis indicate that the 
advance butanol pathway would result in a GHG emissions reduction of 
51.3% compared to the gasoline fuel it would replace.
    Based on our LCA, we are proposing to add a new pathway to Table 1 
to section 80.1426 that includes butanol from corn starch using the 
butanol process described here as an advanced biofuel (D-5 RINs). EPA 
invites comments on the assumptions used in this analysis.
    Table V.F.-2 below breaks down by stage the lifecycle GHG emissions 
for the RFS2 corn butanol pathway, the advanced butanol pathway and the 
2005 gasoline baseline. This table demonstrates the contribution of 
each stage in the fuel pathway and its relative significance in terms 
of GHG emissions.

                  Table V.F.-2--Lifecycle GHG Emissions for the Advanced Butanol Pathway, 2022
                                               [Kg CO2-eq./mmBtu]
----------------------------------------------------------------------------------------------------------------
                                                                RFS2 corn
                                                            ethanol, natural                        RFS2 2005
                         Fuel type                            gas fired dry     GEVO butanol        gasoline
                                                              mill 63% dry                          baseline
                                                                  DDGS
----------------------------------------------------------------------------------------------------------------
Net Domestic Agriculture (w/o land use change)............                 4                 4  ................
Net International Agriculture (w/o land use change).......                12                12  ................
Domestic Land Use Change..................................                -4                -4  ................
International Land Use Change, Mean (Low/High)............        32 (21/46)                31  ................
Fuel Production...........................................                28                 0                19
Fuel and Feedstock Transport..............................                 4                 4                 *
Tailpipe Emissions........................................                 1                 1                79
                                                           -----------------------------------------------------
    Total Emissions, Mean.................................        77 (66/91)                48                98
% Reduction...............................................              -21%              -51%  ................
----------------------------------------------------------------------------------------------------------------
* Emissions included in fuel production stage.

    Table V.F.-3 lists the proposed D-Codes by fuel type (butanol), 
considering the feedstock (corn starch) and different production 
process requirements.

[[Page 36060]]



                                   Table V.F.-3--Proposed D Codes for Butanol
----------------------------------------------------------------------------------------------------------------
                                                                          Production process
            Fuel type                          Feedstock                     requirements             D-Code
----------------------------------------------------------------------------------------------------------------
Butanol..........................  Corn starch.....................  Fermentation; dry mill                    6
                                                                      using natural gas,
                                                                      biomass, or biogas for
                                                                      process energy.
Butanol..........................  Corn starch.....................  Fermentation; dry mill                    5
                                                                      using natural gas and
                                                                      biogas from on-site thin
                                                                      stillage anaerobic
                                                                      digester for process
                                                                      energy w/CHP producing
                                                                      excess electricity of at
                                                                      least 40% of the purchased
                                                                      natural gas energy used by
                                                                      the facility.
----------------------------------------------------------------------------------------------------------------

2. Butanol, Biobutanol, and Volatility Considerations
    Butanol is a flammable colorless liquid that is used as a fuel and 
as an industrial solvent. Butanol is composed of the chemical elements 
hydrogen, oxygen, and carbon. It can be made from petroleum or 
renewable biomass, such as corn, grasses, agricultural waste and other 
renewable sources. It can be used in internal combustion engines as an 
additive to gasoline and is currently registered under the Fuel and 
Fuel Additives Registration System (FFARS) for use at up to 12 volume 
percent. A higher blend level would require a new FFARS registration 
that would include meeting Tier 1 and Tier 2 health effects testing 
requirements. Biobutanol is the common name for butanol made from 
renewable sources.
    There has been an increased interest in the use of biobutanol as a 
direct result of the requirements for increased use of renewable fuel 
volumes, adopted in EISA 2007. These provisions require an increase in 
the use of renewable fuels, with 36 billion gallons of renewable fuel 
to be used in the U.S. by 2022. Parties required to meet these 
standards are interested in cost effective and practical ways to 
satisfy the standards and meet the performance needs of the vehicles 
and engines. Biobutanol is one attractive option because of its higher 
energy density, lower blending vapor pressure, and lower heat of 
vaporization in comparison to ethanol, as well as the fact that it can 
be distributed as a gasoline blend throughout the fungible gasoline 
distribution system.
    The Clean Air Act (section 211(h)(4)) requires EPA to adopt 
regulations limiting the volatility of gasoline during the summer 
months, when ozone is of most concern, including a one pound per square 
inch (psi) Reid Vapor Pressure (RVP) increase in the volatility limit 
for blends of gasoline containing 9-10% ethanol (E10). This allowance 
for a 1 psi increase in allowable volatility is commonly called the 1 
psi waiver.
    EPA's regulations at 40 CFR 80.27 adopt RVP standards that apply to 
the gasoline at all points in the distribution system, including the 
retail outlet. Under the provisions for the 1 psi waiver, blends of 
gasoline that contain from 9 volume percent to 10 volume percent 
ethanol are allowed to have volatility 1 psi higher than otherwise 
would be allowed (40 CFR 80.27(d)(2)). The chemical characteristics of 
ethanol are such that blends of gasoline with less than 9 volume 
percent to 10 volume percent ethanol would still have a significant 
increase in volatility. Thus the restriction on the 1 psi waiver to 
blends that have 9 volume percent to 10 volume percent ethanol has the 
effect of prohibiting the blending of E10 with other gasoline/renewable 
fuel blends at any point in the gasoline distribution system (wholesale 
or retail) in conventional gasoline areas during the summer control 
season. Blends of E10 gasoline and gasoline that is not E10 would have 
less than 9 volume percent or greater than 10 volume percent ethanol, 
would have a resulting increase in volatility compared to E0, but would 
not have the 1 psi waiver to allow for such an increase. This increase 
would lead to an RVP above the allowable limit, unless a sub-RVP 
gasoline blendstock was used. The practical effect is a prohibition on 
commingling of E10 and gasoline blends other than E10.
    Under the current regulations, EPA applies the RVP standard to the 
commingled mixture as a whole, not to the components of the commingled 
mixture. Once the ethanol and non-ethanol blends are mixed, the 
commingled mixture is treated as the gasoline that is tested and 
compared to the RVP standard. A single RVP value is determined by 
testing the volatility of the commingled mixture, and this is compared 
to the standard. If the mixture has from 9 volume percent to 10 volume 
percent ethanol, then the 1 psi waiver applies to the mixture. If the 
mixture has a different percentage of ethanol, whether lower or higher, 
then the 1 psi waiver does not apply to the mixture.
    This avoids a situation where there is an overall increase in 
volatility because of the commingling of E10 and gasoline that is not 
E10. As discussed below, the chemical characteristics of ethanol and 
the nonlinear nature of the volatility increase associated with varying 
volumes of ethanol, mean that mixing E10 gasoline with gasoline that is 
not E10 typically results in a net overall increase in emissions--the 
mixture has a higher volatility and emissions than the separate 
gasolines had on average before they were mixed.
    Several parties have identified this as an obstacle that currently 
inhibits the opportunity for biobutanol to enter the commercial market. 
The primary issue is application of the RVP regulations at the final 
point of fuel dispensing, when the biobutanol (Bu) and the ethanol 
blends would be mixed, that is in a storage tank at the retail station. 
When a butanol product that complies with the RVP standards prior to 
commingling (e.g., a complying Bu12 blend) is commingled with a 
compliant E10 in underground storage tanks at fuel dispensing 
facilities, the resulting mix generally would exceed the applicable RVP 
standard as EPA's RVP regulations currently apply the standard. Certain 
fuels, including renewable biofuels such as butanol, however, do not 
have a net negative impact on RVP when blended with E10 at wholesale or 
retail. That is, the RVP and related emissions of the commingled blend 
of butanol and ethanol is no higher than the average RVP if the fuels 
had never been commingled. Thus, in these kinds of circumstances it may 
be appropriate to adopt a modified approach to applying the RVP 
standard to permit the commingling of complying E10 blends with 
complying butanol blends at wholesale and retail, as there is no 
overall degradation of RVP and the air quality impacts compared to what 
would occur if they were not blended.
    Today, the agency is providing some additional background on this 
issue and requesting information for use in deciding whether EPA can 
and should modify its RVP regulations as discussed below. Specifically, 
we are inviting comment on the ability of regulated parties to comply 
with the existing regulations by segregating biobutanol blends from 
ethanol blends and whether there is a need to change the regulations. 
We are also seeking comment on an alternative approach to applying the 
RVP standards to a commingled mixture of E10 with biobutanol or other 
approved gasoline additives, where the additives have

[[Page 36061]]

characteristics such that there is no net adverse emissions effect from 
the commingling. We are inviting comments as to whether the RVP 
standards can and should be applied such that the commingled mixture of 
E10 and specified blends of gasoline additives such as biobutanol is 
treated as complying with the RVP standard as long as the components of 
that mixture complied with the RVP standard prior to the commingling. 
This approach would provide a limited modification to how the RVP 
standards are applied, and the modification would apply for only 
certain fuel mixtures--those where the overall or net volatility of the 
commingled mixture is no higher than the weighted average of the 
original blends themselves, such that there is no adverse impact on 
emissions from the mixing compared to what would have occurred without 
such mixing. In order to assist parties in preparing comments, EPA is 
providing some additional background regarding the RVP program in the 
following paragraphs.
Background and History of Volatility Regulations
    Reid Vapor Pressure (RVP) is the most common measure of gasoline 
volatility under ambient conditions. In 1989, EPA began reducing 
gasoline volatility by limiting its RVP (54 FR 11868, March 22, 1989) 
(40 CFR 80.27). Due to the presence of gasoline in certain markets 
mixed with about 10 volume percent ethanol (known as gasohol at the 
time), and because blending an alcohol into gasoline increases the 
volatility of the final product, EPA provided an additional 1 psi 
allowance for such blends. In the absence of the 1 psi allowance, a 
special blend stock would have been required for such blends to comply 
with the RVP standards and such sub-RVP blendstocks did not exist at 
the time. EPA imposed the RVP standards at all points in the gasoline 
distribution system, i.e., anywhere gasoline is sold, supplied, offered 
for sale or supply or transported, including service stations, refinery 
shipping, tanks, importer shipping tanks, pipeline and bulk terminals 
and plants. (40 CFR 80.28) (1989). In 1990, the agency promulgated 
additional regulations that further lowered the RVP standards. (55 FR 
23658, June 11, 1990). EPA continued to provide both the 1.0 psi 
allowance to fuel blends containing about 10 volume percent ethanol, 
(40 CFR 80.27) (1990), and the requirement that RVP standards applied 
at all points in the distribution system.
    Congress largely codified the approach taken in EPA's RVP 
regulations by adding a new section 211(h) in the 1990 CAA amendments. 
Section 211(h)(1) requires EPA to set the maximum RVP standard during 
the high ozone season as 9.0 psi. EPA was to ``promulgate regulations 
making it unlawful for any person during the high ozone season to sell, 
offer for sale, dispense, supply, offer for supply, transport, or 
introduce into commerce gasoline with a Reid Vapor Pressure in excess 
of 9.0 pounds per square inch (psi).'' Lower RVP standards could be set 
for ozone nonattainment areas. See Clean Air Act section 211(h)(1). 
Section 211(h)(2) addresses the RVP standard that apply in attainment 
areas, and sets the standard at 9.0 psi for attainment areas with 
authority for EPA to set a more stringent RVP level under certain 
circumstances. In section 211(h)(2), Congress allowed a 1-psi waiver 
for E10 gasoline, stating: ``For fuel blends containing gasoline and 10 
percent denatured anhydrous ethanol, the Reid vapor pressure limitation 
under this subsection shall be one pound per square inch (psi) greater 
than the applicable Reid vapor pressure limitations established under 
paragraph (1).'' Additionally, Congress enacted a conditional defense 
against liability for violations of the RVP level allowed under the 1 
psi waiver by stating that ``[p]rovided; however, that a distributor, 
blender, marketer, reseller, carrier, retailer, or wholesale purchaser-
consumer shall be deemed to be in full compliance with the provisions 
of this subsection and the regulations promulgated there under if it 
can demonstrate that--(A) the gasoline portion of the blend complies 
with the Reid vapor pressure limitations promulgated pursuant to this 
subsection; (B) the ethanol portion of the blend does not exceed its 
waiver condition under subsection (f)(4) of this section; and (C) no 
additional alcohol or other additive has been added to increase the 
Reid Vapor Pressure of the ethanol portion of this blend.'' Section 
211(h)(4).
    In a 1991 rulemaking, EPA modified the RVP regulations to conform 
to the 1990 amendments (56 FR 64704, December 12, 1991). These 
regulations addressed the RVP standards in attainment areas, required 
the use of denatured anhydrous ethanol as a specific condition for the 
1-psi waiver for fuel blends containing gasoline and from 9 volume 
percent to 10 volume percent ethanol, and included a new defense 
against liability for violations of the RVP standards for such fuel 
blends. We made no changes to the requirement that the RVP standards 
applied at all points in the distribution system.
What modification is EPA considering to the application of the RVP 
standards to certain fuel blends?
    Gasoline and ethanol are mixed or blended after the refining 
process. The practice of blending ethanol with gasoline increases the 
RVP of the resulting blend by approximately 1.0 psi. It is a non-linear 
relationship, most of the volatility increase occurs after just a few 
percent of ethanol have been added, with the volatility increasing more 
slowly as the gasoline ethanol blend increases to 10 volume percent. 
Above 10 volume percent the volatility generally does not increase any 
more, and at even higher levels of ethanol the volatility starts to 
decrease again. As explained above, section 211(h)(4) provides a 1-psi 
waiver for fuel blends containing gasoline from 9 volume percent to 10 
volume percent ethanol. The absence of such a waiver would have 
required the creation of a production and distribution network for sub-
9.0 psi RVP gasoline, to offset the increase in volatility associated 
with blending ethanol into the gasoline. At the time the costs of 
producing and distributing an additional grade of this type of fuel, 
especially in consideration of the low volumes of fuel being blended 
with ethanol at the time, would have likely been prohibitive and 
resulted in the termination of the availability of ethanol in the 
marketplace. Thus, the 1-psi waiver facilitated the participation of 
ethanol in the transportation fuel industry while also limiting 
gasoline volatility resulting from ethanol blending.
    But the RVP levels of gasoline actually used by consumers are 
dependent on the mixture of alcohol blends and gasoline that are 
commingling in either vehicle or storage tanks. Depending on the 
mixture, the resulting RVP level could be significantly higher than the 
average volatility of the fuels prior to the commingling. This is 
because the volatility increase when ethanol is added to gasoline is 
non-linear, with a large increase with the first few percent and then 
slowly tapering off as the concentration increases (see Illustration 
V.F.-4). In other words, mixing E10 and EO gasoline results in a net 
increase in the volatility of the gasoline mixture, compared to the 
average volatility that would occur absent such mixing. For example, 
2000 gallons of 10 psi E10 added to a service station tank with 8000 
gallons of 9.0 psi E0 would result in 10,000 gallons of fuel with a 
volatility of approximately 10 psi. However if the fuels had not been 
mixed, the average volatility of the 10000 gallons would

[[Page 36062]]

have been 9.2 psi. The emissions associated with the commingled mixture 
(10000 gallons at 10 psi) would be significantly higher than the 
emissions associated with the two separate blends of 2000 gallons at 10 
psi and 8000 gallons at 9 psi. The commingling thus results in an 
adverse environmental impact compared to what would occur absent the 
commingling. EPA's current RVP regulations address this adverse 
emissions impact by applying the RVP standard to the commingled mixture 
as a single fuel. In this case the commingled mixture has an RVP of 10 
psi. The 1 psi waiver does not apply as the mixture is now 2% ethanol, 
not from 9 volume percent to 10 volume percent ethanol. The commingled 
mixture thus would not comply with the 9.0 psi RVP standard, 
effectively prohibiting such commingling.
    As discussed earlier, the EPAct 2005 and EISA2007 mandated 
increased volumes of renewable fuel for use in gasoline. This has 
resulted in the increased use of ethanol. E10 is now present in nearly 
all gasoline sold in the country. Recently, EPA granted a waiver from 
the substantially similar requirements under section 211(f)(4) for the 
use of E15 blends in MY2001 and newer light-duty vehicles (See 75 FR 
68094, November 4, 2010 and 76 FR 4662, January 26, 2011). EPA 
interpreted section 211(h) as not extending the 1 psi waiver to such 
blends with ethanol levels above 10%. Several companies are also 
developing and planning on introducing biobutanol into commerce. The 
characteristics of butanol are such that it could be beneficial with 
respect to volatility and vehicle evaporative emission performance. For 
example, 2000 gallons of 10 psi E10 added to a service station tank 
with 8000 gallons of 9.0 psi Bu12 would result in 10000 gallons of fuel 
with an RVP of 9.2 psi. The RVP of the commingled blend would be the 
same as the average of the separate blends if they had never been 
commingled. There is no adverse emissions impact from the commingling 
of the E10 and Bu12 blends. However the 1-psi waiver would not be 
applicable because the resulting blend no longer contains from 9 volume 
percent to 10 volume percent ethanol. The RVP level for the resulting 
blend would also be higher than the maximum RVP standard of 9.0 psi, 
making the commingled blend noncomplying with the RVP standard. However 
the available data indicates that commingling of biobutanol blends with 
ethanol blends would not result in any net increase in gasoline 
volatility. This is because biobutanol blends and gasoline containing 
from 9 volume percent to 10 volume percent ethanol blend linearly from 
a volatility perspective, resulting in no net increase in volatility 
compared to what would occur without the blending. This means that 
there would be no net degradation in environmental performance, as 
indicated in Illustration V.F.-4, below.
    We are inviting comment on an alternative approach to applying the 
RVP standard to the gasoline that results from commingling of E10 and 
certain other products like biobutanol. We are inviting comment as to 
whether the RVP standards could be applied to the commingled blend such 
that the commingled blend would be considered in compliance as long as 
the separate components of the commingled product were in compliance 
with the RVP standards prior to commingling. In effect the RVP standard 
would be applied to the commingled mixture by treating it as if it 
still contained two separate products, with each product required to 
comply with the RVP standard separately. This approach would be 
somewhat artificial but would allow for the commingling of specified 
blends of fuels, such as biobutanol, with E10 where the resulting 
commingled mixture does not result in a net increase in average RVP and 
associated emissions. This would provide more flexibility in achieving 
the RFS standards while avoiding adverse environmental impacts. This 
approach would provide a limited modification to the RVP provisions for 
only certain fuel blends. EPA invites comment on whether it would have 
the authority under Sec.  211(h) to adopt such an approach, and if so 
whether it would be appropriate to do so and under what conditions.
    Specifically, we would consider imposing the following conditions 
on such fuel blends:
    (1) Each separate component must individually meet the applicable 
RVP standards (e.g., 10 psi for E10 and 9 psi for other blends).
    (2) The resulting commingled mixture would have to have an RVP that 
is no higher than the weighted average of the products or components 
considered separately. This could occur with blends that blend linearly 
with respect to RVP (e.g., butanol).
    (3) The burden would be on the retailer to show that these 
conditions had been satisfied. If a commingled product had volatility 
above the allowable standard, and did not have from 9 volume percent to 
10 volume percent ethanol, then the fuel would be considered 
noncomplying unless the regulated party demonstrated that it met the 
limited conditions discussed here. The retailer would have to 
demonstrate that the conditions were met for application of this 
modified method of determining compliance. This would call for at least 
retaining records of the products received (with all required 
regulatory statements and indications required) and volumes of the 
products received in order to demonstrate a calculation to verify 
compliance with the RVP standard.
    (4) In situations where the RVP of retail tank samples exceed 9.0/
7.8 psi, for defense purposes the retailer would need to test the 
sample for the concentration of ethanol, butanol, and any other 
applicable oxygenate in addition to the RVP level in order to allow for 
the calculation in (3). The resulting blend ratio would need to meet or 
demonstrate better performance reductions of such ratio on a linear 
scale as established through regulation.
    Under this approach, we believe there would be no adverse 
environmental effects because such mixtures would result in no net 
increase in volatility. We also believe this would enable us to give 
effect to the RFS provisions that call for increased use of renewable 
fuels, and also be consistent with our rational for the treatment of 
gasohol at the time we promulgated the RVP standards.

[[Page 36063]]

[GRAPHIC] [TIFF OMITTED] TP14JN13.001

F. Amendments to Various RFS2 Compliance Related Provisions

    We are proposing a number of changes to the RFS2 regulations.
1. Proposed Changes to Definitions
``Responsible Corporate Officer''
    The existing RFS2 regulations at sections 80.1416, 80.1451 and 
80.1454, and EPA guidance and instructions regarding registration and 
reporting, frequently refer to the responsibilities of the ``owner or a 
responsible corporate officer.'' However, the term ``responsible 
corporate officer'' is not currently defined in the RFS2 regulations. 
We propose that, for purposes of the RFS2 program, a ``responsible 
corporate officer'' (RCO) means a corporate officer who has the 
authority and is assigned responsibility to provide information to EPA 
on behalf of a company. A company may name only one RCO, and the RCO 
may not delegate his/her responsibility to any other person. However, 
the RCO may delegate the ability to submit information to EPA to one or 
more employees of the company or to one or more agents. The RCO remains 
responsible for the information submitted to EPA by any employee or 
agent. Adding a definition of RCO will codify existing practices and 
will assist regulated parties in understanding roles under the RFS2 
regulation.
``Small Refinery''
    Section 211(o)(9)(A) of the Clean Air Act provides an exemption 
from RFS requirements through 2010 for ``small refineries,'' defined as 
refineries having an average aggregate daily crude oil throughput for a 
calendar year that does not exceed 75,000 barrels. It also provides for 
possible extensions of this exemption, through individual petitions to 
EPA. CAA 211(o)(9)(B). In EPA's March 26, 2010 regulations implementing 
the EISA amendments we specified in the regulatory definition of 
``small refinery'' that the 75,000 bpd threshold determination should 
be calculated based on information from calendar year 2006. At the 
beginning of the program, having a single year in which to make this 
determination, simplified the calculations, and helped to ensure that 
all refineries were treated similarly. However, we no longer believe 
that it is appropriate that refineries satisfying the 75,000 bpd 
threshold in 2006 should be eligible for extensions to their small 
refinery RFS exemption if they no longer meet the 75,000 bpd threshold. 
Allowing such facilities to qualify for an exemption extension, while 
not allowing similarly sized facilities that have not grown since 2006 
to qualify for an exemption,

[[Page 36064]]

does not appear fair, nor does it further the objectives of the statute 
to target relief to only truly small facilities. Therefore, we propose 
modifying the definition of small refinery so that the crude throughput 
threshold of 75,000 bpd must apply in 2006 and in all subsequent years. 
We also propose specifying in section 80.1441(e)(2)(iii) that in order 
to qualify for an extension of its small refinery exemption, a refinery 
must meet the definition of ``small refinery'' in section 80.1401 for 
all full calendar years between 2006 and the date of submission of the 
petition for an extension of the exemption.
    We proposed that that these changes would not affect any existing 
exemption extensions under CAA 211(o)(9)(B); rather, they would apply 
at such time as any approved exemption extension expires and the 
refinery at issue seeks a further exemption extension. No further 
extension would be permitted unless the revised crude oil throughput 
specifications were satisfied.
2. Provisions for Small Blenders of Renewable Fuels
    The RFS2 regulations at section 80.1440 allow renewable fuel 
blenders who handle and blend less than 125,000 gallons of renewable 
fuel per year, and who are not obligated parties or exporters, to 
delegate their RIN-related responsibilities to the party directly 
upstream from them who supplied the renewable fuel for blending. EPA 
has received feedback from several parties to the effect that the 
125,000 threshold is too low, and is a lower threshold than what 
industry considers ``small.'' EPA seeks input on what a more 
appropriate gallon threshold should be. EPA seeks comment on the 
regulated community's experience with the existing gallon threshold 
associated with the provisions. EPA may adjust the gallon threshold in 
the final rule based on further consideration of this issue and 
evaluation of comments received.
3. Proposed Changes to Section 80.1450--Registration Requirements
    We propose to add a new paragraph (h) to section 80.1450 that will 
describe the circumstances under which EPA may cancel a company 
registration. EPA proposes to initiate a process to cancel a company 
registration if the company has reported no activity in the EPA 
Moderated Transaction System (EMTS) under section 80.1452 for one year. 
EPA also proposes to initiate a process to cancel a company 
registration if a party fails to comply with any registration 
requirement of section 80.1450, if the party fails to submit any 
required compliance report under section 80.1451, if the party fails to 
meet the requirements related to the EPA Moderated Transaction System 
(EMTS) under section 80.1452, or if the party fails to meet the 
requirements related to attest engagements under section 80.1454. If 
any required report, including the attest engagement, is thirty (30) or 
more days overdue, EPA would provide written notice to the owner or 
responsible corporate officer (RCO) that it intends to cancel the 
company's registration and would allow the company fourteen (14) days 
from the date of the letter's issuance to respond. If there is no 
satisfactory response received, then EPA would cancel the registration. 
Re-registration would be possible following the standard registration 
procedures.
4. Proposed Changes to Section 80.1452--EPA Moderated Transaction 
System (EMTS) Requirements--Alternative Reporting Method for Sell and 
Buy Transactions for Assigned RINs
    Reporting and product transfer document (PTD) requirements, found 
in sections 80.1452 and 80.1453, respectively, currently state that the 
reportable event for a RIN purchase or sale occurs on the date of 
transfer. Sellers must report the sale of RINs within five (5) business 
days of the reportable event via the EPA Moderated Transaction System 
(EMTS). Buyers must report the purchase of RINs within ten (10) 
business days of the reportable event via EMTS. The date of transfer is 
the date on which title of RINs is transferred from the seller to the 
buyer. Some buyers and sellers of assigned RINs have expressed concerns 
with these requirements stating they have difficulty determining the 
date of transfer since title of the renewable fuel is not transferred 
until the fuel physically reaches the buyer. Some transactions, for 
example those by rail or barge, may take several weeks, and their 
current accounting systems do not include a means for capturing the 
buyer's receipt date.
    EPA understands this concern, but also recognizes that some 
regulated parties have modified their accounting systems to address the 
current reporting and PTD requirements in RFS2. We also believe that 
for parties separating, retiring, and selling or buying separated RINs, 
the current reporting and PTD requirements are effective and should 
remain unchanged. Therefore, at this time EPA is not proposing to 
replace existing requirements, but is instead proposing an additional, 
alternative method for reporting sell and buy transactions involving 
assigned RINs only.
    The proposed alternative method for sell and buy transactions of 
assigned RINs would redefine the reportable event for both the seller 
and the buyer, introduce a unique identifier that the seller must 
provide to the buyer, and require the buyer to report the date of 
transfer. Buyers and sellers would need to agree on which method they 
would be using to report transfers of assigned RINs; either the current 
method or the alternative method. EPA believes that this alternative 
would provide the regulated community with the flexibility to address 
their reporting concerns and also provide EPA with the data necessary 
to effectively administer and enforce transactions of assigned RINs. 
EPA welcomes comment on this proposed alternative method for reporting 
assigned RIN buy and sell transactions.
    We propose that sellers of assigned RINs under the alternative 
method be required to do the following:
     Within five (5) business days of shipping renewable fuel 
with assigned RINs, report a sell transaction, using the alternative 
method, via EMTS;
     Include in the EMTS sell transaction report other required 
information per section 80.1452; and
     Provide a PTD to the assigned RIN buyer with a unique 
identifier, also reported via EMTS, in addition to the information in 
section 80.1453. The date of transfer is not required for the 
alternative method.
    We propose that buyers of assigned RINs under the alternative 
method be required to do the following:
     Within five (5) business days of receiving a shipment of 
renewable fuel with assigned RINs, report a buy transaction, indicating 
use of the alternative method, via EMTS;
     Include in the EMTS buy transaction report other required 
information per section 80.1452;
     Include in the EMTS buy transaction report the unique 
identifier provided by the seller; and
     Include in the EMTS buy transaction report the date the 
renewable fuel was received, i.e. the date of transfer.
    If this proposed alternative method is finalized, the EMTS would be 
modified to accept such transactions. EPA would provide additional 
instruction and guidance at the time of the new EMTS version release. 
EPA invites comment on all aspects of this proposal.

[[Page 36065]]

5. Proposed Changes to Section 80.1463--Confirm That Each Day an 
Invalid RIN Remains in the Marketplace Is a Separate Day of Violation
    Preventing the generation and use of invalid RINs and encouraging 
rapid retirement and replacement of invalid RINs is crucial to the 
integrity of the RFS2 program. The RFS regulations include various 
provisions related to prohibited acts and liability for violations. 
Section 80.1460(a) sets forth the prohibited acts for the renewable 
fuels program. Section 80.1460(b)(2) prohibits parties from creating or 
transferring invalid RINs. Section 80.1461(a) states that the person 
who violates a prohibited act is liable for the violation of that 
prohibition. Section 80.1461(b) provides the liability provisions for 
failure to meet other provisions of the regulations. The penalty 
provisions of the regulations at section 80.1463(a) state that any 
person who is liable for a violation under section 80.1461 is subject 
to a civil penalty as specified in sections 205 and 211(d) of the Clean 
Air Act (CAA), for every day of each such violation and the amount of 
economic benefit or savings resulting from each violation. Section 
80.1463(c) provides that ``any person . . . is liable for a separate 
day of violation for each day such a requirement remains unfulfilled.''
    EPA interprets these statutory and regulatory penalty provisions to 
give the Agency the authority to seek penalties against parties 
generating, transferring or causing another person to generate or 
transfer invalid RINs for each day subsequent to the party's action 
that an invalid RIN is available for sale or use by a party subject to 
an obligation under the RFS2 program to acquire and retire RINs. For 
example, for a RIN generator, this time period typically runs from the 
date of invalid RIN generation until either corrective action is taken 
by the RIN generator to remove the invalid RIN from the marketplace or 
a party uses the RIN to satisfy an RVO or other requirement to retire 
RINs (such as would apply under today's proposal to exporters of 
renewable fuel or parties using fuel produced as renewable fuel for a 
use other than as transportation fuel, heating oil or jet fuel). This 
is consistent with the CAA approach of assessing penalties for every 
day of a violation, consistent with EPA's historic approach under the 
fuels regulations (See Section 80.615), and will encourage renewable 
fuel producers that generate invalid RINs to promptly take corrective 
action.
    We are proposing to amend section 80.1463 to more explicitly 
incorporate EPA's interpretation of these penalty provisions into the 
regulations. The amendments would state that any person liable for a 
violation of section 80.1460(b) for creating or transferring an invalid 
RIN, or for causing another person to create or transfer and invalid 
RIN, is subject to a separate day of violation for each day that the 
invalid RIN remains available for use for compliance purposes, and EPA 
has the authority to seek the maximum statutory penalty for each day of 
violation. EPA will apply the statutory factors in sections 211(c) and 
205(b) of the CAA to evaluate the appropriate penalties for each 
violation on a case by case basis.
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
    The current regulations include requirements that foreign renewable 
fuel producers that generate RINs agree to be subject to a number of 
additional requirements at section Sec.  80.1466, including, but not 
limited to, designation, foreign producer certification, product 
transfer document, load port independent testing and producer 
identification, submission to U.S. jurisdiction and posting of a bond. 
We are proposing to require the same requirements for foreign renewable 
fuel producers, and foreign ethanol producers that produce biofuel for 
which importers ultimately generate RINs, and for importers of 
renewable fuel.
    In order to evaluate whether a fuel qualifies as RIN generating 
renewable fuel (including determining the proper renewable fuel 
category and RIN type for the imported fuel), EPA must be able to 
evaluate the feedstocks and processes used to produce the renewable 
components of the fuel. This is a particular challenge for fuel 
produced at foreign facilities; unlike our other fuels programs, EPA 
cannot determine whether a particular shipment of renewable fuel is 
eligible to generate RINs under the RFS program by testing the fuel 
itself. Furthermore, significant opportunity for fraud and non-
compliance with the regulations exists where EPA is not able to ensure 
that RINs entering the U.S. are valid, and where enforcement of the 
regulations may be hampered due to a facility's foreign location. We 
believe that the same safeguards that apply to foreign RIN generating 
renewable fuel producers should apply to other foreign producers whose 
product is used by importers to generate RINs, and to those importers 
themselves. Accordingly, we propose that foreign renewable fuel 
producers and foreign ethanol producers who do not themselves generate 
RINs for their product, and importers of renewable fuel, be required to 
comply with the safeguards of section 80.1466. Given the challenges 
associated with EPA's ability to determine whether a fuel qualifies as 
RIN generating renewable fuel, and the potential for fraud, we believe 
these additional safeguards are necessary for all foreign produced 
renewable fuel, regardless of who generates the RINs. However, we seek 
comment on the reasonability of expanding these additional requirements 
onto foreign renewable fuel producers, and foreign ethanol producers 
that produce biofuel for which importers ultimately generate RINs, and 
for importers of renewable fuel. We further propose to amend section 
80.1426(a)(4) to prohibit importers from generating RINs for renewable 
fuel imported from a foreign renewable fuel producer or foreign ethanol 
producer, unless and until the foreign renewable fuel producer or 
foreign ethanol producer has satisfied all requirements of section 
80.1466.
7. Proposed Changes to Section 80.1466(h)--Calculation of Bond Amount 
for Foreign Renewable Fuel Producers, Foreign Ethanol Producers and 
Importers
    EPA proposes two changes to section 80.1466 regarding calculation 
of bonds. EPA proposes to amend the procedures for calculating the bond 
amount for foreign renewable fuel producers, foreign ethanol producers 
and importers to require that the bond amount be the larger of: (1) One 
cent times the largest volume of renewable fuel produced by the foreign 
producer and exported to the United States, in gallons, during a single 
calendar year among the five preceding calendar years, or the largest 
volume of renewable fuel that the foreign producers expects to export 
to the Unites States during any calendar year identified in the 
Production Outlook Report required by section 80.1449, or (2) the sum 
of the following calculation for each RIN type: 0.25 times the largest 
volume of renewable fuel produced by the foreign producer and exported 
to the United States, in gallons, during a single calendar year among 
the five preceding calendar years, or the largest volume of renewable 
fuel that the foreign producers expects to export to the Unites States 
during any calendar year identified in the Production Outlook Report 
required by section 80.1449, times a ``RIN multiplier D code'' 
established by EPA in the regulations.

[[Page 36066]]

The proposed ``RIN multiplier D codes'' vary from $.02 for D code 6 to 
$1.30 for D code 4. When the original renewable fuels standard 
regulations (RFS1) were written, an RFS1 RIN was worth pennies. With 
the implementation of RFS2, the price of some RINs has increased 
significantly, in part because of the demand for certain categories of 
fuel such as biomass-based diesel. In order to keep up with these 
market conditions, the bond amount needs to be increased; a penny per 
gallon of fuel may no longer be a fair valuation of a foreign renewable 
fuel producer's potential penalty for RFS violations. Bonds are used to 
satisfy any judicial judgment that results from an administrative or 
judicial enforcement action for conduct in violation of this subpart. 
Therefore, we propose to amend section 80.1466(h)(1) to include the 
calculation described above, that reflects current market valuation for 
different types of RINs. We seek comment on whether the proposed bond 
calculation procedures are appropriate, and in particular whether they 
are sufficiently large to cover potential liability.
    EPA also proposes to amend paragraph (h) of section 80.1466 to be 
consistent with paragraph (j)(4), which prohibits generating RINs in 
excess of the number for which the bond requirements have been 
satisfied. Paragraph (h) regulates the size of the bond a foreign 
renewable fuel producer must post in order to generate RINs. This 
formula takes into account the volume of renewable fuel a foreign 
renewable fuel producer has exported or intends to export to the United 
States. Section 80.1466(h) states, in part: ``If the volume of 
renewable fuel exported to the United States increases above the 
largest volume identified in the Production Outlook Report during any 
calendar year, the foreign producer shall increase the bond to cover 
the shortfall within 90 days.'' This conflicts with the stricter 
language in paragraph (j)(4) of the same section, which prohibits a 
foreign producer of renewable fuel from generating RINs in excess of 
the number for which the bond requirements of section 80.1466 have been 
satisfied. EPA interprets the stricter provision at section 
80.1466(j)(4) to be controlling, and we propose to change the language 
in section 80.1466(h) accordingly.
8. Proposed Changes to Facility's Baseline Volume To Allow ``Nameplate 
Capacity'' for Facilities Not Claiming Exemption From the 20% GHG 
Reduction Threshold
    As a requirement of registration under the RFS2 program, each 
renewable fuel producer and foreign ethanol producer must establish and 
provide documents to support its facility's baseline volume as defined 
in section 80.1401. This is either the permitted capacity or, if 
permitted capacity cannot be determined, the actual peak capacity of a 
specific renewable fuel production facility on a calendar year basis. 
After the promulgation of the March 26, 2010 RFS2 rule, we have 
received many requests from companies to allow them to use their 
nameplate or ``design'' capacity to establish their facility's baseline 
volume due to either the facility being exempt from obtaining a permit, 
and thus not able to determine their permitted capacity, or the 
facility not starting operations, or not being operational for a full 
calendar year to produce actual production records to establish actual 
peak capacities. Because the regulations currently only allow a 
facility's baseline volume to be established by a limit stated in a 
permit or actual production records for at least one calendar year, 
facilities that had neither a permit or sufficient production records 
had difficulty registering under the RFS2 program. To allow facilities 
that fall under this predication to register under the RFS2 program, we 
are proposing in this rulemaking to allow a facility to use its 
``nameplate capacity'' to establish its facility's baseline volume for 
the purposes of registration, only if (1) the facility does not have a 
permit or there is no limit stated in the permit to establish their 
permitted capacity, and (2) has not started operations or does not have 
at least one calendar year of production records, and (3) does not 
claim exemption from the 20 percent GHG threshold under Sec.  80.1403. 
Due to the complexity of the exemption provision provided under Sec.  
80.1403, and the added flexibility that facilities claiming this 
exemption are allotted under the program, we are not proposing to 
extend this option to facilities claiming an exemption under Sec.  
80.1403. Additionally, by this stage in the RFS2 program, the 
facilities that would qualify for registration under Sec.  80.1403 
would be very few, if any. This proposal would revise the definition of 
baseline volume to include ``nameplate capacity,'' add a new definition 
for ``nameplate capacity'' to Sec.  80.1401, and include conforming 
amendments to the registration requirements of Sec.  80.1450.

G. Minor Corrections to RFS2 Provisions

    We are proposing a number of corrections to address minor 
definitional issues that have been identified as we have been 
implementing the RFS2 program.
Renewable Biomass
    We propose to amend the definition of ``renewable biomass'' in 
section 80.1401 to make clear that biomass obtained in the vicinity of 
buildings means biomass obtained within 200 feet of the buildings. The 
preamble for the March 26, 2010 RFS2 final rule cites the distance of 
200 feet (see 75 FR 14696), but EPA did not include a reference to this 
value in the regulations. We believe doing so would provide additional 
clarity to the regulations.
English Language Translations
    We propose to add a new paragraph (i) to section 80.1450 to state 
that any registration materials submitted to EPA must be in English or 
accompanied by an English language translation. Similarly, we propose 
to add a new paragraph (h) to section 80.1451 that will state that any 
reports submitted to EPA must be in English or accompanied by an 
English language translation and add a new paragraph (q) to section 
80.1454 that will state that any records submitted to EPA must be in 
English or accompanied by an English language translation. The 
translation and all other associated documents must be maintained by 
the submitting company for a period of five (5) years, which is already 
the established time period for keeping records under the existing RFS2 
program.
Correction of Typographical Errors
    We propose to correct various typographical errors in section 
80.1466. Specifically, we propose to amend paragraph (o) to correct a 
typographical error in the last sentence of the affirmation statement, 
by changing the citation from Sec.  80.1465 to Sec.  80.1466. We also 
propose to amend paragraph (d)(3)(ii) to correct a typographical error. 
The current regulation cites section 80.65(e)(2)(iii), which does not 
exist. The correct citation is to section 80.65(f)(2)(iii).

VI. Amendments to the E15 Misfueling Mitigation Rule

    We propose the following minor corrections and other changes to the 
E15 misfueling mitigation rule (E15 MMR) found at 40 CFR Part 80, 
subpart N.

A. Proposed Changes to Section 80.1501--Label

    We propose to correct several minor errors in the description of 
the E15 label required by the E15 MMR at section 80.1501, including 
corrections in the dimensions of the label and ensuring that the word 
``ATTENTION'' is capitalized. The Agency intended the label required by 
the regulations to look

[[Page 36067]]

identical to that pictured in the Federal Register notice for the final 
E15 MMR (see 76 FR 44406, 44418, July 25, 2011).

B. Proposed Changes to Section 80.1502--E15 Survey

    We are proposing two changes to the survey requirements found at 
section 80.1502. First, we propose to clarify that E15 surveys need to 
sample for Reid vapor pressure (RVP) only during the high ozone season 
as defined in section 80.27(a)(2)(ii) or during any time RVP standards 
apply in any state implementation plan approved or promulgated under 
the Clean Air Act. EPA did not intend to require RVP sampling and 
testing during the rest of the year, when RVP standards do not apply.
    Second, we propose to change when the results of surveys that 
detect potential noncompliance must be reported to the Agency. As 
originally drafted, the regulations require the independent survey 
association conducting a survey to notify EPA of potentially 
noncompliant samples within 24 hours of the laboratory receiving this 
sample (see 76 FR at 44423, July 25, 2011). EPA has since learned that 
more time may be needed for reporting of noncompliant samples since it 
may take several days for analysis of the sample to be completed. We 
are therefore requiring that noncompliant samples be reported to EPA 
within 24 hours of being analyzed.

C. Proposed Changes to Section 80.1503--Product Transfer Documents

    EPA is proposing certain minor changes to the product transfer 
document (PTD) requirements found at section 80.1503. Specifically, we 
are proposing to allow the use of product codes for conventional 
blendstock/gasoline upstream of an ethanol blending facility, since 
historically, the codes have been allowed to be used for conventional 
blendstock/gasoline upstream of an ethanol blending facility in other 
fuels programs. This was an omission from the original regulation.
    We are also seeking comment on potential ways of streamlining the 
PTD language required at section 80.1503.

D. Proposed Changes to Section 80.1504--Prohibited Acts

    EPA is slightly rewording section 80.1504(g) to state that blending 
E10 that has taken advantage of the statutory 1.0 psi RVP waiver during 
the summertime RVP control period with a gasoline-ethanol fuel that 
cannot take advantage of the 1.0 psi RVP waiver (i.e., a fuel that 
contains more than 10.0 volume percent ethanol (e.g., E15) or less than 
9 volume percent ethanol) would be a violation of the E15 MMR. As 
originally written, the language does not clearly describe the 
prohibited activity (see 76 FR 44435, 44436, Jult 25, 2011).

E. Proposed Changes to Section 80.1500--Definitions

    On August 17, 2011, the National Petroleum Refiners Association, 
now called American Fuel and Petrochemical Manufacturers (AFPM), filed 
a petition for reconsideration with the Agency under CAA section 
307(d)(7)(B) asking EPA to reconsider certain portions of the E15 MMR. 
A copy of the petition has been placed in the docket. The petition 
fundamentally focuses on one issue--AFPM expressed concern that the 
Agency had defined E10 and E15 in the E15 MMR in a way that would 
change how ethanol concentrations are determined for regulatory 
purposes. Today we grant AFPM's request for reconsideration of this 
issue as explained in their August 17, 2011 petition. As explained 
below, while EPA did not intend the definitions of E10 and E15 in the 
E15 MMR to have this effect, we are proposing changes to the 
regulations to avoid this perceived impact.
    On April 6, 1979, fuel containing 90% unleaded gasoline and 10% 
ethyl alcohol received a waiver under section 211(f)(4) by operation of 
law (see 44 FR 20777, April 6, 1979). Later, EPA issued an 
interpretative ruling that stated the April 6, 1979 waiver covered 
gasoline-ethanol blends that contained up to 10 vol% ethanol content 
(see 47 FR 14596, April 5, 1982). Finally, in the context of 
regulations limiting the Reid vapor pressure (RVP) of gasoline, EPA has 
defined E10 as gasoline containing between 9 and 10 volume percent 
ethanol. Under the RVP regulations and the Clean Air Act, the RVP of 
E10 is allowed to be 1 pound per square inch (psi) higher than it is 
for gasoline or gasoline-ethanol blends containing less than 9 and more 
than 10 vol% ethanol (often referred to as the ``1.0 psi waiver'').
    In the E15 MMR, EPA defined E10 as gasoline containing at least 9.0 
and no more than 10.0 vol% ethanol and defined E15 as a gasoline-
ethanol blend containing greater than 10.0 and no more than 15.0 vol% 
ethanol. EPA included those definitions in the E15 MMR so that fuels 
blended to contain more than 10.0 vol% ethanol were subject to the 
misfueling mitigation requirements for E15. After publication of the 
E15 MMR, stakeholders including AFPM expressed concern that by defining 
E10 as E10.0, the Agency may have effectively made the ethanol 
concentration limits specified in the E10 and the E15 waiver decisions 
and the RVP regulations more stringent, which in turn would impact 
whether a party must comply with the E15 MMR requirements and whether a 
fuel qualifies for the RVP 1.0 psi waiver.
    In its petition, AFPM noted that under existing EPA regulations at 
40 CFR 80.9, the results of compliance testing for the ethanol 
concentration in gasoline are ``rounded down'' when the results 
indicate that gasoline-ethanol fuel may contain slightly more than 10 
vol% ethanol. AFPM further stated that in view of this rounding 
procedure, fuel that compliance testing indicates has an ethanol 
concentration of between 10.0 and 10.4 should be considered E10. AFPM 
argued that the E15 MMR definition of E10 as containing no more than 
10.0 vol% ethanol constituted a ``substantive change'' to the proposed 
E15 MMR that would also alter the implementation of other EPA fuels 
regulations without a required rulemaking.
    As part of the E15 MMR proposed rule, we identified prospective 
responsible parties for each misfueling mitigation measure, including 
requirements related to labeling E15 fuel dispensers, compliance 
surveys, and product transfer documents. We received a number of 
comments from many affected stakeholders, including AFPM, that asked us 
to clarify which party or parties would be responsible for each 
misfueling mitigation measure and when each party or parties would be 
subject to those requirements. In the final E15 MMR, we added the 
significant digit to the definitions of E10 and E15 in order to provide 
a delineation between E10 and E15 and consequently the parties subject 
to one or more of the E15 misfueling mitigation measures.
    AFPM argued in their petition that by defining E10 as containing no 
more than 10.0 vol% ethanol, EPA effectively made a substantive change 
to the way test results used for determining compliance with fuel 
requirements are rounded. For example, for a gasoline-ethanol blend to 
be considered E10, it could no longer contain up to 10.4 vol% ethanol; 
it could only contain up to 10.04 vol% ethanol. AFPM asserted that 
there is a tolerance for blending ethanol that allows blends containing 
up to 10.4 vol% ethanol to be considered E10. While we do not agree 
that there is a blending tolerance for ethanol, we agree that test 
results are rounded utilizing the procedures identified in section 80.9 
when compared to applicable standards, in this case the ethanol 
concentrations

[[Page 36068]]

specified in the E10 and the E15 waivers.
    The Agency specifically addressed the issue of blending tolerances 
versus testing tolerances for gasoline-ethanol blends in the RFS2 
NPRM.\50\ At the time, some stakeholders had suggested that the 
implementation of a blending tolerance for the ethanol content of 
gasoline could be allowed to help obligated parties satisfy RFS 
requirements without the need for a CAA section 211(f)(4) waiver. In 
response, we argued that although the test methods used to measure 
ethanol concentration (ASTM D 5599 and ASTM D 4815) include some 
variability, ethanol is different than other fuel properties and 
components that are controlled in other fuel programs.\51\ Fuel 
properties such as RVP, and components such as sulfur and benzene, are 
natural characteristics of gasoline as a result of the chemical nature 
of crude oil and the refining process. Their levels or concentrations 
in gasoline are unknown until measured and are dependent upon the 
accuracy of the test method. In contrast, ethanol is intentionally 
added in known amounts using equipment designed to ensure a specific 
concentration within a very narrow range. Parties that blend ethanol 
into gasoline normally have precise control over the final 
concentration. Therefore, a blending tolerance for ethanol would not be 
appropriate. During the comment period for the RFS2 NPRM, EPA received 
a number of comments from stakeholders that argued that the volume 
percentage of ethanol in gasoline is readily determined using very 
accurate volumetric ratio blending facilities now in place at most 
blending terminals; therefore, the Agency should not allow a blending 
tolerance. In the final RFS rule, we did not include a blending 
tolerance for ethanol blends.\52\
---------------------------------------------------------------------------

    \50\ See 74 FR 25018 (May 26, 2009).
    \51\ See 74 FR 25018 (May 26, 2009).
    \52\ See 75 FR 14762-14764 (March 26, 2010).
---------------------------------------------------------------------------

    We continue to believe that blending tolerances for ethanol are not 
appropriate, and the definitions of E10 and E15 in the E15 MMR are 
consistent with this view. The E10 waiver is for gasoline containing 
``up to'' 10 vol% ethanol, not for gasoline containing ``up to'' 10.4 
vol% ethanol, and the E15 partial waivers are for fuel designed to 
contain ``greater than 10 vol% ethanol and not more than 15 vol% 
ethanol.'' In the case of both waivers, the ``10'' and the ``15'' are 
exact numbers, not approximations, and they express how much ethanol 
can be lawfully added to fuel. Testing by the Department of Energy 
utilized in making the E15 partial waiver decisions was blended as 
precisely as possible to contain the relevant percentage of ethanol, 
not that percentage plus ``0.49.'' Testing for registration of E10 and 
E15 fuel and fuel additives under 40 CFR part 79 was also done with 
fuels blended as precisely as possible to contain the relevant 
percentage of ethanol. Similarly, EPA regulations provide that only 
fuel with an ethanol concentration of between 9 and 10 vol%, not more 
or less, may lawfully use the statutory 1.0 psi RVP waiver.
    At the same time, we did not intend to change the definition of E10 
in a way that impacts the rounding of test results for ethanol 
concentrations.\53\ If a manufacturer blends in a way designed to 
result in a gasoline-ethanol fuel containing no more than 10.0 vol% 
ethanol, but compliance testing indicates a concentration of 10.4 vol%, 
we will still round down the test result in accordance with procedures 
in section 80.9. The purpose of the E15 MMR definitions state that if a 
manufacturer blends ethanol into gasoline in a way designed to result 
in a gasoline-ethanol fuel containing greater than 10.0 vol% and no 
more than 15.0 vol% ethanol, it will be subject to applicable E15 MMR 
requirements. For example, bills of lading for an E10 fuel manufacturer 
that indicates the manufacturer has purchased and blended more ethanol 
than 10.0 vol% ethanol may indicate that a fuel does not meet the 
definition of E10 for E15 MMR purposes.
---------------------------------------------------------------------------

    \53\ For an explanation of the rounding procedures outlined in 
Sec.  80.9 and the rationale the Agency used to adopt those 
procedures, see 71 FR 16496 (April 3, 2006).
---------------------------------------------------------------------------

    AFPM also argued that the E15 MMR definitions of E10 would alter 
the implementation of other EPA fuels regulations without a required 
rulemaking, specifically the application of the 1.0 psi RVP waiver to 
E10. Since the Agency intended the E15 MMR definition of E10 to only 
apply for purposes of determining the applicability of E15 MMR 
requirements, the Agency does not believe these definitions affect the 
implementation and enforcement of others fuels programs, including the 
applicability of the 1.0 psi RVP waiver. The introductory language to 
the definitions at 40 CFR part 80, subpart N clearly states that 
definitions in section 80.1500 are ``[f]or purposes of this subpart 
only.''
    In order to clarify that these definitions only apply in the 
context of the E15 MMR, EPA is proposing to add a new section 80.1509, 
which contains language that clearly states that when ethanol 
concentrations are measured for compliance testing purposes for 40 CFR, 
Part 80, Subpart N, the applicable ethanol concentration value will be 
rounded using the rounding procedures at section 80.9. EPA is also 
proposing new prohibited acts language in section 80.1504 that should 
make it clear that only those parties that (1) produce gasoline, 
blendstocks for oxygenate blending (BOBs), or ethanol designed to be 
used in the manufacture of E15 as currently defined (i.e., E15.0); (2) 
that manufacture E15 to be introduced into commerce; or (3) that 
dispense E15 from a retail outlet. The Agency specifically seeks 
comments on this proposed language.

VII. Proposed Amendments to the ULSD Diesel Sulfur Survey

    EPA is requesting comment concerning whether to amend a provision 
of the ultra-low sulfur diesel (ULSD) rule. The ULSD rule includes a 
provision that deems branded refiners liable for violations of the ULSD 
sulfur standard that are found at retail outlets displaying the 
refiner's brand (40 CFR 80.612). The regulations include defense 
provisions. One element of a branded refiner's defense to such 
violations is that it must have a periodic sampling and testing program 
at the retail level (40 CFR 80.613(b) and (d)). The regulations also 
set forth an alternative sampling and testing defense element provision 
for branded refiners.
    This alternative defense element provision (40 CFR 80.613(e)) 
allows a branded refiner to meet the company-specific downstream 
periodic sampling and testing element of its defense by participating 
in funding a survey consortium that samples diesel fuel at retail 
outlets nationwide. This sampling and testing of fuel to determine 
compliance with the ULSD sulfur standard is carried out by an 
independent survey association. EPA reviews and approves the annual 
survey plan submitted by the survey association. The number of samples 
that are taken each year is determined by a statistical formula that is 
based in part on the previous year's compliance rate. In addition, the 
regulations set a floor and a ceiling for the number of samples that 
must be taken in an annual survey cycle regardless of the sample number 
that would be calculated using the regulatory formula. Therefore, the 
number of samples required to be taken can potentially be less than the 
formula would require, or it can be more.
    Compliance with the ULSD sulfur content standard has been extremely 
high; less than 1% of the samples have been in violation in recent 
years. The

[[Page 36069]]

minimum number of samples currently required to be taken annually is 
set by the regulation at 5,250 regardless of this high compliance rate. 
Due to the high compliance rate, use of the statistical formula would 
result in a sampling rate of several hundred samples for each of the 
past several years, instead of 5,250 samples. The cost difference 
between taking several hundred samples versus taking over 5,000 samples 
is significant. For these reasons we believe the continued high 
compliance rate, and the substantial discrepancy between the sampling 
rate calculated by the formula and the minimum sampling rate, argue for 
lowering the minimum sampling rate. However, we believe there is a 
point where the number of samples per year would be so few that the 
survey would be meaningless relative to robust sampling and testing 
programs conducted by each refiner individually. Balancing these 
concerns, we believe minimum sampling rate of about 1,800 samples is 
appropriate. We are requesting comment on reducing the minimum number 
of samples to some rate below 2,000 samples.

VIII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order 12866 (58 FR 51735, October 4, 1993), this 
action is a ``significant regulatory action'' because it raises novel 
legal or policy issues. Accordingly, EPA submitted this action to the 
Office of Management and Budget (OMB) for review under Executive Orders 
12866 and 13563 (76 FR 3821, January 21, 2011) and any changes made in 
response to OMB recommendations have been documented in the docket for 
this action.

B. Paperwork Reduction Act

    The information collection requirements in this notice of proposed 
rulemaking have been submitted for approval to the Office of Management 
and Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et 
seq. The Information Collection Request (ICR) document prepared by EPA 
related to this proposal has been assigned EPA ICR number 2469.01. A 
supporting statement for the proposed ICR has been placed in the 
docket. The proposed information collection is described in the 
following paragraphs.
    This action contains recordkeeping and reporting that may affect 
the following parties under the RFS2 regulation: RIN generators 
(producers, importers), obligated parties (refiners), exporters, and 
parties who own or transact RINs. We estimate that 670 parties may be 
subject to the proposed information collection. We estimate an annual 
recordkeeping and reporting burden of 3.1 hours per respondent. This 
action contains recordkeeping and reporting that may affect the 
following parties under the E15 regulation: gasoline refiners, gasoline 
and ethanol importers, gasoline and ethanol blenders (including 
terminals and carriers). We estimate that 2,000 respondents may be 
subject to the proposed information collection. We estimate an annual 
recordkeeping and reporting burden of 1.3 hours per respondent. Burden 
means the total time, effort, or financial resources expended by 
persons to generate, maintain, retain, or disclose or provide 
information to or for a Federal agency. This includes the time needed 
to review the instructions; develop, acquire, install, and utilize 
technology and systems for the purpose of collecting, validating, and 
verifying information, processing and maintaining information, and 
disclosing and providing information; adjust the existing ways to 
comply with any previously applicable instructions and requirements; 
train personnel to be able to respond to a collection of information; 
search data sources; complete and review the collection of information; 
and transit or otherwise disclose the information. Burden is as defined 
at 5 CFR 1320.3(b).
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for EPA's 
regulations in 40 CFR are listed in 40 CFR Part 9.
    To comment on the Agency's need for this information, the accuracy 
of the provided burden estimates, and any suggested methods for 
minimizing respondent burden, EPA has established a public docket for 
this proposed rule, which includes the ICR described above, under 
Docket ID number EPA-HQ-OAR-2012-0401. Submit any comments related to 
the ICR to EPA and OMB. See the ADDRESSES section at the beginning of 
this notice for where to submit comments to EPA. Send comments to OMB 
at the Office of Information and Regulatory Affairs, Office of 
Management and Budget, 725 17th Street NW., Washington, DC 20503, 
Attention: Desk Office for EPA. Since OMB is required to make a 
decision concerning the ICR between 30 and 60 days after June 14, 2013, 
a comment to OMB is best assured of having its full effect if OMB 
receives it by July 15, 2013.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements under the Administrative 
Procedure Act or any other statute unless the agency certifies that the 
rule will not have a significant economic impact on a substantial 
number of small entities. Small entities include small businesses, 
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of today's rule on small 
entities, small entity is defined as: (1) A small business as defined 
by the Small Business Administration's (SBA) regulations at 13 CFR 
121.201; (2) a small governmental jurisdiction that is a government of 
a city, county, town, school district or special district with a 
population of less than 50,000; and (3) a small organization that is 
any not-for-profit enterprise which is independently owned and operated 
and is not dominant in its field.
    After considering the economic impacts of this action on small 
entities, I certify that this action will not have a significant 
economic impact on a substantial number of small entities. The 
amendments to the RFS2 provisions in this direct final rule will not 
impose any requirements on small entities that were not already 
considered under the final RFS2 regulations, as it makes relatively 
minor corrections and modifications to those regulations. We continue 
to be interested in the potential impacts of the proposed rule on small 
entities and welcome comments on issues related to such impacts.

D. Unfunded Mandates Reform Act

    This rule does not contain a Federal mandate that may result in 
expenditures of $100 million or more for State, local, and tribal 
governments, in the aggregate, or the private sector in any one year. 
We have determined that this action will not result in expenditures of 
$100 million or more for the above parties and thus, this rule is not 
subject to the requirements of sections 202 or 205 of UMRA.
    This rule is also not subject to the requirements of section 203 of 
UMRA because it contains no regulatory requirements that might 
significantly or uniquely affect small governments. It only applies to 
gasoline, diesel, and renewable fuel producers, importers, distributors 
and marketers and makes relatively minor corrections and

[[Page 36070]]

modifications to the RFS2 and diesel regulations.

E. Executive Order 13132 (Federalism)

    This action does not have federalism implications. It will not have 
substantial direct effects on the States, on the relationship between 
the national government and the States, or on the distribution of power 
and responsibilities among the various levels of government, as 
specified in Executive Order 13132. This action only applies to 
gasoline, diesel, and renewable fuel producers, importers, distributors 
and marketers and makes relatively minor corrections and modifications 
to the RFS2 and diesel regulations. Thus, Executive Order 13132 does 
not apply to this action. In the spirit of Executive Order 13132, and 
consistent with EPA policy to promote communications between EPA and 
State and local governments, EPA specifically solicits comment on this 
proposed action from State and local officials.

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

    This proposed rule does not have tribal implications, as specified 
in Executive Order 13175 (65 FR 67249, November 9, 2000). It applies to 
gasoline, diesel, and renewable fuel producers, importers, distributors 
and marketers. This action makes relatively minor corrections and 
modifications to the RFS and diesel regulations, and does not impose 
any enforceable duties on communities of Indian tribal governments. 
Thus, Executive Order 13175 does not apply to this action. EPA 
specifically solicits additional comment on this proposed action from 
tribal officials.

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

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

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

    This action is not a ``significant energy action'' as defined in 
Executive Order 13211 (66 FR 28355, (May 22, 2001)), because it is not 
likely to have a significant adverse effect on the supply, 
distribution, or use of energy. This action amends existing regulations 
related to renewable fuel, E15, and ultra-lower sulfur diesel. We have 
concluded that this rule is not likely to have any adverse energy 
effects. In fact, we expect this proposed rule may result in positive 
effects, because many of the changes we are proposing will facilitate 
the introduction of new renewable fuels under the RFS2 program and have 
come at the suggestion of industry stakeholders.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (``NTTAA''), Public Law 104-113, 12(d) (15 U.S.C. 272 note) 
directs EPA to use voluntary consensus standards in its regulatory 
activities unless to do so would be inconsistent with applicable law or 
otherwise impractical. Voluntary consensus standards are technical 
standards (e.g., materials specifications, test methods, sampling 
procedures, and business practices) that are developed or adopted by 
voluntary consensus standards bodies. NTTAA directs EPA to provide 
Congress, through OMB, explanations when the Agency decides not to use 
available and applicable voluntary consensus standards.
    This action does not involve technical standards. Therefore, EPA 
did not consider the use of any voluntary consensus standards. EPA 
welcomes comments on this aspect of the proposed rulemaking and, 
specifically, invites the public to identify potentially-applicable 
voluntary consensus standards and to explain why such standards should 
be used in this regulation.

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

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

K. Clean Air Act Section 307(d)

    This rule is subject to Section 307(d) of the CAA. Section 
307(d)(7)(B) provides that ``[o]nly an objection to a rule or procedure 
which was raised with reasonable specificity during the period for 
public comment (including any public hearing) may be raised during 
judicial review.'' This section also provides a mechanism for the EPA 
to convene a proceeding for reconsideration, ``[i]f the person raising 
an objection can demonstrate to the EPA that it was impracticable to 
raise such objection within [the period for public comment] or if the 
grounds for such objection arose after the period for public comment 
(but within the time specified for judicial review) and if such 
objection is of central relevance to the outcome of the rule.'' Any 
person seeking to make such a demonstration to the EPA should submit a 
Petition for Reconsideration to the Office of the Administrator, U.S. 
EPA, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave. NW., 
Washington, DC 20460, with a copy to both the person(s) listed in the 
preceding FOR FURTHER INFORMATION CONTACT section, and the Director of 
the Air and Radiation Law Office, Office of General Counsel (Mail Code 
2344A), U.S. EPA, 1200 Pennsylvania Ave. NW., Washington, DC 20460.

List of Subjects in 40 CFR Part 80

    Environmental protection, Administrative practice and procedure, 
Agriculture, Air pollution control, Confidential business information, 
Energy, Forest and Forest Products, Fuel additives, Gasoline, Imports, 
Motor vehicle pollution, Penalties, Petroleum, Reporting and 
recordkeeping requirements.

    Dated: May 20, 2013.
Bob Perciasepe,
Acting Administrator.

    For the reasons stated in the preamble, the Environmental 
Protection Agency proposes to amend 40 CFR chapter I as set forth 
below:

[[Page 36071]]

PART 80--REGULATION OF FUELS AND FUEL ADDITIVES

0
1. The authority citation for part 80 continues to read as follows:

    Authority:  42 U.S.C. 7414, 7521, 7542, 7545 and 7601(a).

0
2. Section 80.613 is amended by revising paragraph (e)(4)(v)(A) 
definition ``n'' as follows:


Sec.  80.613  What defenses apply to persons deemed liable for a 
violation of a prohibited act under this subpart?

* * * * *
    (e) * * *
    (4) * * *
    (v) * * *
    (A) * * *

Where:

n= minimum number of samples in a year-long survey series. However, 
in no case shall n be larger than 9,600 nor smaller than 1,800.
* * * * *
0
3. Section 80.1401 is amended by adding the definitions of ``Nameplate 
capacity'', ``Renewable compressed natural gas'', ``Renewable fuel 
producer'', ``Renewable liquefied natural gas'', ``Responsible 
corporate officer'', in alphabetical order and revising the definitions 
of ``Biogas'', ``Crop residue'', ``Naphtha'', ``Renewable biomass'', 
and ``Small refinery'' in to read as follows:


Sec.  80.1401  Definitions.

* * * * *
    Biogas means 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. Biogas includes landfill gas, gas from 
waste digesters, and gas from waste treatment plants. Waste digesters 
include digesters processing animal wastes, biogenic waste oils/fats/
greases, separated food and yard wastes, and crop residues, and waste 
treatment plants include wastewater treatment plants and publicly owned 
treatment works.
* * * * *
    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, nor any other impact that 
would result in a significant increase in direct or indirect GHG 
emissions.
* * * * *
    Nameplate capacity means the peak design capacity of a facility for 
the purposes of registration of a facility under Sec.  
80.1450(b)(1)(V)(E).
    Naphtha means a blendstock or fuel blending component falling 
within the boiling range of gasoline which is composed of only 
hydrocarbons, is commonly or commercially known as naphtha and is used 
to produce gasoline through blending.
* * * * *
    Renewable biomass means each of the following (including any 
incidental, de minimis contaminants that are impractical to remove and 
are related to customary feedstock production and transport):
    (1) Planted crops and crop residue harvested from existing 
agricultural land cleared or cultivated prior to December 19, 2007 and 
that was nonforested and either actively managed or fallow on December 
19, 2007.
    (2) Planted trees and tree residue from a tree plantation located 
on non-federal land (including land belonging to an Indian tribe or an 
Indian individual that is held in trust by the U.S. or subject to a 
restriction against alienation imposed by the U.S.) that was cleared at 
any time prior to December 19, 2007 and actively managed on December 
19, 2007.
    (3) Animal waste material and animal byproducts.
    (4) Slash and pre-commercial thinnings from non-federal forestland 
(including forestland belonging to an Indian tribe or an Indian 
individual, that are held in trust by the United States or subject to a 
restriction against alienation imposed by the United States) that is 
not ecologically sensitive forestland.
    (5) Biomass (organic matter that is available on a renewable or 
recurring basis) obtained from the immediate vicinity (i.e., obtained 
within 200 feet) of buildings and other areas regularly occupied by 
people, or of public infrastructure, in an area at risk of wildfire.
    (6) Algae.
    (7) Separated yard waste or food waste, including recycled cooking 
and trap grease, and materials described in Sec.  80.1426(f)(5)(i).
    Renewable compressed natural gas means biogas as defined in this 
section, 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. Only renewable CNG that qualifies as renewable fuel and is used 
for transportation purposes can generate RINs.
* * * * *
    Renewable fuel producer means a person who operates or directly 
supervises the operation of a facility where renewable fuel is 
produced.
* * * * *
    Renewable liquefied natural gas means biogas as defined in this 
section, 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. Only renewable LNG that qualifies as renewable fuel and is 
used for transportation fuel can generate RINs.
    Responsible Corporate Officer, or RCO, for this subpart only, means 
a corporate officer who has the authority and is assigned 
responsibility to provide information to EPA on behalf of a company. A 
company may name only one Responsible Corporate Officer. A Responsible 
Corporate Officer may not delegate his or her responsibility to any 
other person. The Responsible Corporate Officer may delegate the 
ability to submit information to EPA, but the Responsible Corporate 
Officer remains responsible for the actions of such employees or 
agents.
* * * * *
    Small Refinery, for this subpart only, means a refinery for which 
the average aggregate daily crude oil throughput for calendar year 2006 
and subsequent years (as determined by dividing the aggregate 
throughput for the calendar year by the number of days in the calendar 
year) does not exceed 75,000 barrels.
0
4. Section 80.1415 is amended by revising paragraphs (b)(5) and (c)(1) 
to read as follows:


Sec.  80.1415  How are equivalence values assigned to renewable fuel?

    (b) * * *
    (5) 77,000 Btu (lower heating value) of compressed natural gas 
(CNG) or liquefied natural gas (LNG) shall represent one gallon of 
renewable fuel with an equivalence value of 1.0.
    (c) * * *
    (1) The equivalence value for renewable fuels described in 
paragraph (b)(7) of this section shall be calculated using the 
following formula:

EV = (R/0.972) * (EC/77,000)

Where:


[[Page 36072]]


EV = Equivalence Value for the renewable fuel, rounded to the 
nearest tenth.
R = Renewable content of the renewable fuel. Except as provided in 
Sec.  80.1426(f)(4)(iii), this is a measure of the portion of a 
renewable fuel that came from renewable biomass, expressed as a 
fraction, on an energy basis.
EC = Energy content of the renewable fuel, in Btu per gallon (lower 
heating value).

0
5. Section 80.1426 is amended by:
0
a. Revising Table 1 of paragraph (f)(1) by:
0
1. Revising the entry for ``Q''; and
0
2. Adding new entries for T through AA to the end of the table;
0
b. Revising paragraphs (f)(10) and f(11); and
0
c. Adding paragraph (f)(14).
    The revisions and additions read as follows:


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

    (f) * * *
    (1) * * *

         Table 1 to Sec.   80.1426--Applicable D Codes for Each Fuel Pathway for Use in Generating RINs
----------------------------------------------------------------------------------------------------------------
                                                                             Production process
                               Fuel type               Feedstock                requirements            D-Code
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
Q.....................  Renewable Compressed    Biogas from waste       Any........................            5
                         Natural Gas,            treatment plants and
                         Renewable Liquefied     waste digesters.
                         Natural Gas.
 
                                                  * * * * * * *
T.....................  Butanol...............  Corn starch...........  Fermentation; dry mill                 5
                                                                         using natural gas and
                                                                         biogas from on-site thin
                                                                         stillage anaerobic
                                                                         digester for process
                                                                         energy w/CHP producing
                                                                         excess electricity of at
                                                                         least 40% of the purchased
                                                                         natural gas energy used by
                                                                         the facility.
U.....................  Renewable Compressed    Biogas from Landfills.  Any........................            3
                         Natural Gas,
                         Renewable Liquefied
                         Natural Gas.
V.....................  Renewable Electricity.  Biogas from landfills.  Any........................            3
W.....................  Cellulosic Naphtha....  Biogas from landfills.  Fischer-Tropsch process;               3
                                                                         Facilities must produce at
                                                                         least 20% of their
                                                                         electricity usage at the
                                                                         facility.
X.....................  Cellulosic Diesel for   Biogas from landfills.  Fischer-Tropsch process;               7
                         use as conventional                             Facilities must produce at
                         diesel fuel.                                    least 20% of their
                                                                         electricity usage at the
                                                                         facility.
Y.....................  Naphtha...............  Biogas from landfills.  Fischer-Tropsch process....            5
Z.....................  Renewable Diesel for    Biogas from landfills.  Fischer-Tropsch process;               4
                         use as conventional                             Excluding processes that
                         diesel fuel.                                    co-process renewable
                                                                         biomass and petroleum.
AA....................  Renewable Diesel for    Biogas from landfills.  Fischer-Tropsch process;               5
                         use as conventional                             Includes only processes
                         diesel fuel.                                    that co-process renewable
                                                                         biomass and petroleum.
----------------------------------------------------------------------------------------------------------------

* * * * *
    (10)(i) For purposes of this section, renewable electricity that is 
not introduced into a distribution system with electricity derived from 
non-renewable feedstocks is considered renewable fuel and the producer 
may generate RINs if all of the following apply:
    (A) The electricity is produced from renewable biomass and 
qualifies for a D code in Table 1 to this section or has received 
approval for use of a D code by the Administrator;
    (B) The fuel producer has entered into a written contract for the 
sale of a specific quantity of renewable electricity as transportation 
fuel; and
    (C) The renewable electricity is used as a transportation fuel.
    (ii) For purposes of this section, fuels produced from biogas that 
is not introduced into a distribution system with gas derived from non-
renewable feedstocks is considered renewable fuel and the producer may 
generate RINs if all of the following apply:
    (A) The fuel is produced from renewable biomass and qualifies for a 
D code in Table 1 to this section or has received approval for use of a 
D code by the Administrator;
    (B) The fuel producer has entered into a written contract for the 
sale of a specific quantity of biogas to be used as a feedstock for 
transportation fuel; and
    (C) The fuel produced from the biogas is used as a transportation 
fuel.
    (iii) A producer of renewable electricity that is generated by co-
firing a combination of renewable biomass and fossil fuel may generate 
RINs only for the portion attributable to the renewable biomass, using 
the procedure described in paragraph (f)(4) of this section.
    (11)(i) For purposes of this section, renewable electricity that is 
introduced into a commercial distribution system (transmission grid) 
may be considered renewable fuel and the producer may generate RINs if:
    (A) The electricity is produced from renewable biomass and 
qualifies for a D code in Table 1 of this section or has received 
approval for use of a D code by the Administrator;
    (B) The fuel producer has entered into a written contract for the 
sale of a specific quantity of electricity derived from renewable 
biomass sources with a party that uses electricity taken from a 
commercial distribution system for use as a transportation fuel, and 
such electricity has been introduced into that commercial distribution 
system (transmission grid);
    (C) The quantity of renewable electricity for which RINs were 
generated was sold for use as transportation fuel and for no other 
purposes; and
    (D) The renewable electricity was loaded onto and withdrawn from a 
physically connected transmission grid as defined by the North American 
Electrical Reliability Corporation (NERC) regions.
    (ii) For purposes of this section, fuel produced from biogas that 
is introduced

[[Page 36073]]

into a commercial distribution system may be considered renewable fuel 
and the producer may generate RINs if:
    (A) The fuel is produced from renewable biomass and qualifies for a 
D code in Table 1 of this section or has received approval for use of a 
D code by the Administrator;
    (B) The fuel producer has entered into a written contract for the 
sale of a specific quantity of fuel derived from renewable biomass 
sources with a party that uses fuel taken from a commercial 
distribution system for transportation fuel, and such fuel has been 
introduced into that commercial distribution system (e.g., pipeline);
    (C) The quantity of fuel produced from the biogas for which RINs 
were generated was sold for use as transportation fuel and for no other 
purposes;
    (D) The biogas was injected into and withdrawn from a physically 
connected carrier pipeline;
    (E) The gas that is ultimately withdrawn from that pipeline for use 
in a transportation fuel is withdrawn in a manner and at a time 
consistent with the transport of gas between the injection and 
withdrawal points; and
    (F) The volume and heat content of biogas injected into the 
pipeline and the volume of gas withdrawn to make a transportation fuel 
are measured by continuous metering.
    (iii) The fuel sold for use in transportation fuel is considered 
produced from renewable biomass only to the extent that:
    (A) The amount of fuel sold for use as transportation fuel matches 
the amount of fuel derived from renewable biomass that the producer 
contracted to have placed into the commercial distribution system; and
    (B) No other party relied upon the contracted volume of biogas or 
renewable electricity for the creation of RINs.
    (iv) For renewable electricity that is generated by co-firing a 
combination of renewable biomass and fossil fuel, the producer may 
generate RINs only for the portion attributable to the renewable 
biomass, using the procedure described in paragraph (f)(4) of this 
section.
* * * * *
    (14) For purposes of verification, in order for facilities to meet 
the renewable electricity production requirement for the biogas-derived 
cellulosic diesel and cellulosic naphtha pathways, all conditions below 
apply.
    (i) The quantity of process electricity produced on-site must be 
measured by continuous metering.
    (ii) The electricity must be used to provide power to process units 
or process equipment at the facility.
    (iii) The electrical energy must derive 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.
0
6. Section 80.1427 is amended by:
0
a. Revising paragraphs (a)(1), (a)(1)(i) definition 
``RVOCB,i'', (a)(1)(ii) definition ``RVOBBD,i'', 
(a)(1)(iii) definition ``RVOAB,i'', (a)(1)(iv) definition 
``RVORF,i, (a)(5) introductory text, and (a)(6); and
0
b. Adding paragraph (a)(1)(v), (a)(1)(vi), (a)(1)(vii), (a)(1)(viii),
    The additions and revisions read as follows:


Sec.  80.1427  How are RINs used to demonstrate compliance?

    (a) Renewable Volume Obligations and Exporter Renewable Volume 
Obligations. (1) Except as specified in paragraph (b) of this section 
or Sec.  80.1456, each party that is an obligated party under Sec.  80 
1406 and is obligated to meet the Renewable Volume Obligations under 
Sec.  80.1407, or is an exporter of renewable fuel that is obligated to 
meet the Exporter Renewable Volume Obligations under Sec.  80.1430, 
must demonstrate pursuant to Sec.  80.1451(a)(1) that it is retiring 
for compliance purposes a sufficient number of RINs to satisfy the 
following equations.
    (i) * * *

RVOCB,i = The renewable Volume Obligation for cellulosic 
biofuel for the obligated party for calendar year i, in gallons, 
pursuant to Sec.  80.1407.

    (ii) * * *

RVOBBD,i = The renewable Volume Obligation for biomass-
based diesel for the obligated party for calendar year i, in 
gallons, pursuant to Sec.  80.1407.

    (iii) * * *

RVOAB,i = The renewable Volume Obligation for advanced 
biofuel for the obligated party for calendar year i, in gallons, 
pursuant to 80.1407.

    (iv) * * *

RVORF,i = The renewable Volume Obligation for renewable 
fuel for the obligated party for calendar year i, in gallons, 
pursuant to 80.1407.

    (v) Cellulosic biofuel--Exporter.

([Sigma]RINNUM)CB,i+ ([Sigma]RINNUM)CB,i-1= 
ERVOCB,i

Where:

([Sigma]RINNUM)CB,i= Sum of all owned gallon-RINs that 
are valid for use in complying with the cellulosic biofuel ERVO, 
were generated in year i, and are being applied towards the 
ERVOCB,i, in gallons.
([Sigma]RINNUM)CB,i-1= Sum of all owned gallon-RINs that are valid 
under subparagraph (6) of this paragraph for use in complying with 
the cellulosic biofuel ERVO, were generated in year i-1, and are 
being applied towards the ERVOCB,i, in gallons.
ERVOCB, k= The Exporter Renewable Volume Obligation for 
cellulosic biofuel for the renewable fuel exporter for an export of 
renewable fuel k, in gallons, pursuant to Sec.  80.1430.

    (vi) Biomass-based diesel--Exporter.

([Sigma]RINNUM)BBD,i+ ([Sigma]RINNUM)BBD,i-1= 
ERVOBBD,i

Where:

([Sigma]RINNUM)BBD,i= Sum of all owned gallon-RINs that 
are valid for use in complying with the biomass-based diesel ERVO, 
were generated in year i, and are being applied towards the 
ERVOBBD,i, in gallons.
([Sigma]RINNUM)BBD,i-1= Sum of all owned gallon-RINs that are valid 
under subparagraph (6) of this paragraph for use in complying with 
the biomass-based diesel ERVO, were generated in year i-1, and are 
being applied towards the ERVOBBD,i, in gallons.
ERVOBBD,i= The Exporter Renewable Volume Obligation for 
biomass-based diesel for the renewable fuel exporter for an export 
of renewable fuel I after 2010, in gallons, pursuant to Sec.  
80.1430.

    (vii) Advanced biofuel--Exporter.

([Sigma]RINNUM)AB,i+ ([Sigma]RINNUM)AB,i-1= 
ERVOAB,i

Where:

([Sigma]RINNUM)AB,i= Sum of all owned gallon-RINs that 
are valid for use in complying with the advanced biofuel ERVO, were 
generated in year i, and are being applied towards the 
ERVOAB,i, in gallons.
([Sigma]RINNUM)AB,i-1= Sum of all owned gallon-RINs that are valid 
under subparagraph (6) of this paragraph for use in complying with 
the advanced biofuel ERVO, were generated in year i-1, and are being 
applied towards the ERVOAB,i, in gallons.
ERVOAB,i= The Exporter Renewable Volume Obligation for 
advanced biofuel for the renewable fuel exporter for an export of 
renewable fuel i, in gallons, pursuant to Sec.  80.1430.

    (viii) Renewable fuel--Exporter.

([Sigma]RINNUM)RF,i+ ([Sigma]RINNUM)RF,i-1= 
ERVORF,i

Where:

([Sigma]RINNUM)RF,i= Sum of all owned gallon-RINs that 
are valid for use in complying with the renewable fuel (D code 6) E 
ERVORF,i, in gallons.
([Sigma]RINNUM)RF,i-1= Sum of all owned gallon-RINs that are valid 
under subparagraph (6) of this paragraph for use in complying with 
the renewable fuel (D code 6) ERVO, were generated in year i-

[[Page 36074]]

1, and are being applied towards the ERVORF,i, in 
gallons.
ERVORF,i= The exporter Renewable Volume Obligation for 
renewable fuel for the renewable fuel exporter for an export of 
renewable fuel i, in gallons, pursuant to Sec.  80.1430.
* * * * *
    (5) The value of ([Sigma]RINNUM)i-1 may not exceed values 
determined by the following inequalities as provided in paragraph 
(a)(7)(iii) of this section and 80.1442(d), for obligated parties only.
* * * * *
    (6) Except as provided in paragraph (a)(7) of this section:
    (i) For obligated parties, RINs may only be used to demonstrate 
compliance with the RVOs for the calendar year in which they were 
generated or the following calendar year.
    (ii) [Reserved.]
    (iii) For Renewable Fuel Exporters, RINs generated in calendar year 
i, must be used to demonstrate compliance with the ERVOs from renewable 
fuel export(s) in calendar year i, except as provided in paragraph 
(a)(6)(iv) of this section.
    (iv) For Renewable Fuel Exporters, RINs generated in calendar year 
i-1, may only be used to demonstrate compliance with the ERVOs from 
renewable fuel exports in January of calendar year i.
* * * * *
0
7. Section 80.1441 is amended by adding paragraph (e)(2)(iii) to read 
as follows:


Sec.  80.1441  Small refinery exemption.

* * * * *
    (e) * * *
    (2) * * *
    (iii) In order to qualify for an extension of its small refinery 
exemption, a refinery must meet the definition of ``small refinery'' in 
Sec.  80.1401 for all full calendar years between 2006 and the date of 
submission of the petition for an extension.
* * * * *
0
8. Section 80.1450 is amended by:
0
a. Adding paragraph (b)(1)(iv)(C);
0
b. Revising paragraphs (b)(1)(v)(C), (b)(1)(v)(D); and adding 
(b)(1)(v)(E); and
0
c. Adding paragraphs (h) and (i).
    The additions and revisions read as follows:


Sec.  80.1450  What are the registration requirements under the RFS 
program?

* * * * *
    (b) * * *
    (1) * * *
    (iv) * * *
    (C) To demonstrate compliance with the renewable electricity 
production requirement for the biogas-derived cellulosic diesel and 
cellulosic naphtha pathways, provide all the following information:
    (1) The energy source, equipment and/or process used to generate 
the electricity. Permitted sources are raw landfill gas, waste heat 
from the production process, unconverted syngas from the Fischer-
Tropsch process, fuel gas from the hydroprocessing, or combined heat-
and-power (CHP) units that use non-fossil fuel based gas or other 
renewable sources.
    (2) Estimates of the total amount of electricity to be used, the 
total amount of grid electricity to be purchased, the total amount of 
renewable electricity to be produced, and a calculation of the percent 
of total process electricity use to be produced from allowed sources at 
the facility.
    (v) * * *
    (C)(1) For all facilities, copies of documents demonstrating each 
facility's actual peak capacity as defined in Sec.  80.1401 if the 
maximum rated annual volume output of renewable fuel is not specified 
in the air permits specified in paragraphs (b)(1)(v)(A) and 
(b)(1)(v)(B) of this section, as appropriate.
    (2) For facilities claiming the exemption described in Sec.  
80.1403 (c) or (d) which are exempt from air permit requirements and 
for which insufficient production records exist to establish actual 
peak capacity, copies of document demonstrating the facility's 
nameplate capacity, as defined in Sec.  80.1401.
    (D) For all facilities producing renewable electricity or fuel from 
biogas that qualifies as renewable fuel, submit all relevant 
information in Sec.  80.1426(f)(10) or (11), and copies of all 
contracts that the track the biogas or renewable electricity from its 
original source, to the producer that processes it into renewable fuel, 
and finally to the end user that will actually use the renewable 
electricity or the renewable fuel derived from biogas for 
transportation purposes.
    (1) Specific quantity and the heat content, percent efficiency of 
transfer, if applicable, and any conversion factors of the biogas or 
renewable biomass.
    (2) Specific quantity and the heat content and percent efficiency 
of transfer, if applicable, and any conversion factors for the 
renewable fuel derived from biogas or renewable electricity.
    (E) Such other records as may be requested by the Administrator.
* * * * *
    (h) Cancellation of Company Registration. (1) EPA may cancel a 
company's registration, using the process in paragraph (h)(2) of this 
section, if any of the following circumstances exist:
    (i) The company has reported no activity in EMTS for one calendar 
year (January 1 through December 31) or has failed to meet any EMTS 
requirement under Sec.  80.1452;
    (ii) The company has failed to comply with the registration 
requirements of this section;
    (iii) The company has failed to submit any required report within 
thirty (30) days of the required submission date under Sec.  80.1451; 
or
    (iv) The attest engagement required under Sec.  80.1454 has not 
been received within thirty (30) days of the required submission date.
    (2) EPA will use the following process whenever it decides to 
cancel the registration of a company:
    (i) EPA will notify the company's owner or Responsible Corporate 
Officer (RCO), in writing, that it intends to cancel the company's 
registration, and identifying the reasons for that proposed action. The 
company will have fourteen (14) calendar days from the date of the 
notification to correct the deficiencies identified or explain why 
there is no need for corrective action.
    (ii) If the basis for EPA's notice of intent to cancel registration 
is the absence of EMTS activity for one calendar year, a stated intent 
to engage in activity reported through EMTS within the next calendar 
year will be sufficient to avoid cancellation of registration.
    (iii) If the company does not respond, does not correct identified 
deficiencies, or does not explain why such correction is not necessary 
within the time allotted for response, EPA may cancel the company's 
registration within further notice to the party.
    (3) Impact of registration cancellation.
    (i) A company whose registration is cancelled shall still be liable 
for violation of any requirements of this subpart.
    (ii) A company whose registration is cancelled will not be listed 
on any public list of actively registered companies that is maintained 
by EPA.
    (iii) If the company whose registration is cancelled is a renewable 
fuel producer or foreign ethanol producer, it will not be listed on any 
public list of registered producers maintained by EPA.
    (iv) A company whose registration is cancelled will not have access 
to any of the electronic reporting systems associated with the 
renewable fuel standard program, including the EPA Moderated 
Transaction System (EMTS).

[[Page 36075]]

    (v) A company whose registration is canceled must submit any 
corrections of deficiencies to EPA on forms, and following policies, 
established by EPA.
    (vi) If a company whose registration has been canceled wishes to 
re-register, they may initiate that process by submitting a new 
registration, consistent with paragraphs (a)-(c) of this section.
    (vii) English language registrations. Any document submitted to EPA 
under Sec.  80.1450 must be submitted in English, or shall include an 
English translation.
0
9. Section 80.1451 is amended by revising paragraphs (a)(1)(vi) and 
(b)(1)(ii)(Q), and by adding paragraph (h) to read as follows:


Sec.  80.1451  What are the reporting requirements under the RFS 
program?

    (a) * * *
    (1) * * *
    (vi) The RVOs for obligated parties, as defined in Sec.  80.1427(a) 
and for exporters of renewable fuel, as defined in Sec.  80.1427(a) and 
80.1430(b), for the reporting year.
* * * * *
    (b) * * *
    (1) * * *
    (ii) * * *
    (Q) Producers or importers of renewable fuel produced at facilities 
that use biogas for process heat as described in Sec.  80.1426(f)(12), 
shall report the total energy supplied to the renewable fuel facility, 
in MMBtu based on metering of gas volume. Producers or importers of 
renewable fuel produced at facilities that meet the renewable 
electricity production requirement for the biogas-derived cellulosic 
diesel and cellulosic naphtha pathways as described in Sec.  
80.1426(f)(13), shall report the total renewable electricity produced 
by the renewable facility, in kilowatt-hour (kWh) or megawatt-hour 
(MWh), the total amount of electricity used, the total amount of grid 
electricity purchased, and a calculation verifying the percent of total 
process electricity from allowed sources produced on-site.
* * * * *
    (h) English language reports. Any document submitted to EPA under 
Sec.  80.1451 must be submitted in English, or shall include an English 
translation.
0
10. Amend Section 80.1452 to revise paragraph (c) introductory text and 
add paragraphs (e) and (f) to read as follows:


Sec.  80.1452  What are the requirements related to the EPA Moderated 
Transaction System (EMTS)?

* * * * *
    (c) Starting July 1, 2010, each time any party sells, separates, or 
retires RINs generated on or after July 1, 2010, all of the following 
information must be submitted to EPA via the submitting party's EMTS 
account within five (5) business days of the reportable event, except 
as provided in Sec.  80.1430(f). Starting July 1, 2010, each time any 
party purchases RINs generated on or after July 1, 2010, all the 
following information must be submitted to EPA via the submitting 
party's EMTS account within ten (10) business days of the reportable 
event. The reportable event for a RIN separation occurs on the date of 
separation as described in Sec.  80.1429. The reportable event for a 
RIN retirement occurs on the date of retirement as described in this 
subpart.
* * * * *
    (e) [Reserved.]
    (f) [Reserved.]
0
11. Amend Section 80.1454 by
0
a. Adding paragraph (a)(7);
0
b. Revising paragraph (b)(4)(i);
0
c. Adding paragraph (b)(7);
0
d. Revising paragraph (f)(3)(i) and adding paragraph (f)(5); and
0
e. Revising paragraph (k)(1); and
0
f. Adding paragraph (q).
    The additions and revisions read as follows:


Sec.  80.1454  What are the recordkeeping requirements under the RFS 
program?

* * * * *
    (a) * * *
    (7) Records related to any volume of renewable fuel that was 
disqualified by the party pursuant to Sec.  80.1433:
    (b) * * *
    (4) * * *
    (i) A list of the RINs owned, purchased, sold, separated, retired, 
or reinstated.
* * * * *
    (7) Records related to any volume of renewable fuel where RINs were 
not generated by the renewable fuel producer or importer pursuant to 
Sec.  80.1426(c):
* * * * *
    (f) * * *
    (3) * * *
    (i) A list of the RINs owned, purchased, sold, separated, retired, 
or reinstated.
* * * * *
    (5) Records related to any volume of renewable fuel that was 
disqualified by the party pursuant to Sec.  80.1433.
* * * * *
    (k)(1) Biogas and electricity in pathways involving feedstocks 
other than grain sorghum. A renewable fuel producer that generates RINs 
for renewable CNG/LNG or renewable electricity produced from renewable 
biomass for fuels that are used for transportation pursuant to Sec.  
80.1426(f)(10) and (11), or that uses process heat from biogas to 
generate RINs for renewable fuel pursuant to Sec.  80.1426(f)(12) or 
that meets the renewable electricity production requirement for the 
biogas-derived cellulosic diesel and cellulosic naphtha pathways 
pursuant to Sec.  80.1426(f)(13) shall keep all of the following 
additional records:
    (i) Documents demonstrating the kilowatt-hours (kWh) of allowable 
electricity relied upon under Sec.  80.1426(f)(13) that was generated 
at the facility, if applicable.
    (ii) The energy source, equipment and/or process used to generate 
the electricity relied upon under Sec.  80.1426(f)(13), if applicable. 
Permitted sources are raw landfill gas, waste heat from the production 
process, unconverted syngas from the Fischer-Tropsch process, fuel gas 
from the hydroprocessing, or combined heat-and-power (CHP) units that 
use non-fossil fuel based gas or other renewable sources.
    (iii) Contracts and documents memorializing the sale of renewable 
CNG/LNG or renewable electricity for use as transportation fuel relied 
upon in Sec.  80.1426(f)(10), Sec.  80.1426(f)(11), or for use of 
biogas for use as process heat to make renewable fuel as relied upon in 
Sec.  80.1426(f)(12) and the transfer of title of the biogas or 
renewable electricity and all associated environmental attributes from 
the point of generation to the facility which sells or uses the fuel 
for transportation purposes.
    (iv) Documents demonstrating the volume and energy content of 
biogas, or kilowatts of renewable electricity, relied upon under Sec.  
80.1426(f)(10) that was delivered to the facility which sells or uses 
the fuel for transportation purposes.
    (v) Documents demonstrating the volume and energy content of 
biogas, or kilowatts of renewable electricity, relied upon under Sec.  
80.1426(f)(11), or biogas relied upon under Sec.  80.1426(f)(12) that 
was placed into the common carrier pipeline (for biogas) or 
transmission line shared power grid (for renewable electricity).
    (vi) Documents demonstrating the volume and energy content of 
biogas relied upon under Sec.  80.1426(f)(12) at the point of 
distribution.
    (vii) Affidavits from the biogas or renewable electricity producer 
and all parties that held title to the biogas or renewable electricity 
confirming that title and environmental attributes of the biogas or 
renewable electricity relied upon under Sec.  80.1426(f)(10) and (11) 
were used for transportation purposes only, and that the environmental 
attributes of the biogas or process

[[Page 36076]]

electricity relied upon under Sec.  80.1426(f)(12) or Sec.  
80.1426(f)(13) were used for process heat or electricity at the 
renewable fuel producer's facility, and for no other purpose. The 
renewable fuel producer shall create and/or obtain these affidavits at 
least once per calendar quarter.
    (viii) The biogas or renewable electricity producer's Compliance 
Certification required under Title V of the Clean Air Act.
    (ix) Documents demonstrating the total amount of grid electricity 
purchased and calculations showing the percent of total electricity 
usage provided by allowable electricity production at the facility, if 
applicable.
    (x) Such other records as may be requested by the Administrator.
* * * * *
    (q) English language records. Any document requested by the 
Administrator under this section must be submitted in English, or shall 
include an English translation.
0
12. Section 80.1463 is amended by adding paragraph (d) to read as 
follows:


Sec.  80.1463  What penalties apply under the RFS program?

* * * * *
    (d) Any person violating Sec.  80.1460(b)(1)-(4) or (6) engages in 
a separate violation for each day that an invalid RIN remains available 
for use in RFS compliance, and each such daily violation is punishable 
by the maximum daily penalty allowed under the Clean Air Act.
0
13. Section 80.1466 is amended by revising the section heading and 
paragraphs (a), (d)(1), (d)(1)(vi), (d)(3)(ii), (e)(1)(i), (f) 
introductory text, (h), (h)(1), and (o)(2) and adding paragraph (p) as 
follows:


Sec.  80.1466  What are the additional requirements under this subpart 
for RIN-generating foreign producers, non RIN-generating foreign 
producers, foreign ethanol producers and importers of renewable fuels?

    (a) Foreign producer of renewable fuel. For purposes of this 
subpart, a foreign producer of renewable fuel is a person located 
outside the United States, the Commonwealth of Puerto Rico, the Virgin 
Islands, Guam, American Samoa, and the Commonwealth of the Northern 
Mariana Islands (collectively referred to in this section as ``the 
United States'') that has been registered with EPA as a renewable fuel 
producer or foreign ethanol producer, regardless of whether the foreign 
renewable fuel producer generates RINs or an importer of renewable fuel 
generates RINs for the fuel. Hereinafter referred to as a ``foreign 
producer'' under this section.
    (d) * * * (1) On each occasion that RFS-FRRF is loaded onto a 
vessel for transport to the United States the foreign producer shall 
have an independent third party do all the following:
* * * * *
    (vi) Review original documents that reflect movement and storage of 
the RFS-FRRF from the foreign producer to the load port, and from this 
review determine all the following:
* * * * *
    (3) * * *
    (ii) Be independent under the criteria specified in Sec.  
80.65(f)(2)(iii); and
* * * * *
    (e) * * * (1)(i) Any foreign producer and any United States 
importer of RFS-FRRF shall compare the results from the load port 
testing under paragraph (d) of this section, with the port of entry 
testing as reported under paragraph (k) of this section, for the volume 
of renewable fuel, standardized per Sec.  80.1426(f)(8), except as 
specified in paragraph (e)(1)(ii) of this section.
* * * * *
    (f) Foreign producer commitments. Any foreign producer shall commit 
to and comply with the provisions contained in this paragraph (f) as a 
condition to being approved as a foreign producer under this subpart.
* * * * *
    (h) Bond posting. Any foreign producer shall meet the requirements 
of this paragraph (h) as a condition to approval as a foreign producer 
under this subpart and on a continuing basis if the foreign producer 
exceeds projections used in calculated the bond.
    (1) The foreign producer shall post a bond of the amount calculated 
using one of the two following equations whichever equation results in 
a higher bond value:

Bond = G * $0.01


Or

Bond = .25 * [Sigma](Mi * RINi)

Where:

Bond = amount of the bond in U.S. dollars.
G = the greater of: the largest volume of renewable fuel produced by 
the foreign producer and exported to the United States, in gallons, 
during a single calendar year among the five preceding calendar 
years, or the largest volume of renewable fuel that the foreign 
producer expects to export to the Unites States during any calendar 
year identified in the Production Outlook Report required by Sec.  
80.1449. If the volume of renewable fuel anticipated to be exported 
to the United States during any calendar year increases above the 
value used in calculating the existing bond amount, the foreign 
producer shall increase the bond by using the higher anticipated 
export volume for the calendar year to calculate a higher bond 
amount and purchasing the higher bond prior to the generation of 
RINs to reflect the increase in export volume. Mi = RIN 
multiplier for specified D code, i, in U.S. dollars, as follows:
    The RIN multiplier for a D3 RIN is $0.78
    The RIN multiplier for a D4 RIN is $1.30
    The RIN multiplier for a D5 RIN is $0.80
    The RIN multiplier for a D6 RIN is $0.02
    The RIN multiplier for a D7 RIN is $0.78
    RINi = the greater of: (i) the largest quantity of 
RINs for a specified D code, i, produced by the foreign producer and 
exported to the United States, in gallons, during a single calendar 
year among the five preceding calendar years, or (ii) the largest 
quantity of RINs that the foreign producer expects to export to the 
United States during any calendar year identified in the Production 
Outlook Report required by Sec.  80.1449. If the volume of renewable 
fuel anticipated to be exported to the United States during any 
calendar year increases above the value used in calculating the 
existing bond amount, the foreign producer shall increase the bond 
by using the higher anticipated export volume for the calendar year 
to calculate a higher bond amount and purchasing the higher bond 
prior to the generation of RINs to reflect the increased export 
volume.
* * * * *
    (o)
    (2) Signed by the president or owner of the foreign producer 
company, or by that person's immediate designee, and shall contain the 
following declaration: ``I hereby certify: (1) That I have actual 
authority to sign on behalf of and to bind [INSERT NAME OF FOREIGN 
PRODUCER] with regard to all statements contained herein; (2) that I am 
aware that the information contained herein is being Certified, or 
submitted to the United States Environmental Protection Agency, under 
the requirements of 40 CFR part 80, subpart M, and that the information 
is material for determining compliance under these regulations; and (3) 
that I have read and understand the information being Certified or 
submitted, and this information is true, complete and correct to the 
best of my knowledge and belief after I have taken reasonable and 
appropriate steps to verify the accuracy thereof. I affirm that I have 
read and understand the provisions of 40 CFR part 80, subpart M, 
including 40 CFR 80.1466 apply to [INSERT NAME OF FOREIGN PRODUCER]. 
Pursuant to Clean Air Act section 113(c) and 18 U.S.C. 1001, the 
penalty for furnishing false, incomplete or misleading information in 
this certification or submission is a fine of

[[Page 36077]]

up to $10,000 U.S., and/or imprisonment for up to five years.''
    (p) Foreign Produced Renewable Fuel and Foreign Produced Ethanol 
for Which RINs Have Been or Will Be Generated by the Importer
    (1) For non-RIN generating foreign producers and foreign ethanol 
producers already registered pursuant to section Sec.  80.1450, all of 
the requirements in paragraphs (a) through (o) of this section must be 
satisfied no later than January 1, 2013.
    (2) For RIN generating foreign producers and foreign ethanol 
producers already registered pursuant to section Sec.  80.1450 and 
80.1466, paragraph (h) of this section must be satisfied no later than 
January 1, 2013 if the required amount in paragraph (h) of this section 
exceeds the original amount of the bond posted when the producer was 
originally approved under 80.1466.
0
14. Section 80.1500 is amended by revising the definitions of E10, E15, 
and EX to read as follows:


Sec.  80.1500  Definitions.

* * * * *
    E10 means a gasoline-ethanol blend that contains at least 9 and no 
more than 10 volume percent ethanol.
    E15 means a gasoline-ethanol blend that contains greater than 10 
volume percent ethanol and not more than 15 volume percent ethanol.
    EX means a gasoline-ethanol blend that contains less than 9 volume 
percent ethanol where X equals the maximum volume percent ethanol in 
the gasoline-ethanol blend.
* * * * *
0
15. Section 80.1501 is amended by revising the section 80.1501 heading 
paragraphs (a) introductory text, (b)(3)(i) and (iv), and (b)(4)(ii) to 
read as follows:


Sec.  80.1501  What are the labeling requirements that apply to 
retailers and wholesale purchaser-consumers of gasoline-ethanol blends 
that contain greater than 10 volume percent ethanol and not more than 
15 volume percent ethanol?

    (a) Any retailer or wholesale purchaser-consumer who sells, 
dispenses, or offers for sale or dispensing E15 shall affix the 
following conspicuous and legible label to the fuel dispenser:
* * * * *
    (b) * * *
    (3) * * *
    (i) The word ``ATTENTION'' shall be capitalized in 20-point, 
orange, Helvetica Neue LT 77 Bold Condensed font, and shall be placed 
in the top 1.25 inches of the label as further described in (b)(4)(iii) 
below.
* * * * *
    (iv) The words ``Use only in'' shall be in 20-point, left-
justified, black, Helvetica Bold font in the bottom 1.875 inches of the 
label.
    (4) * * *
* * * * *
    (ii) The background of the bottom 1.875 inches of the label shall 
be orange.
* * * * *
0
16. Section 80.1502 is amended by revising paragraphs (b)(3)(iii)(A), 
(b)(3)(iv), (b)(4)(iv)(B), (b)(4)(v)(A), (c)(4), and (c)(6) to read as 
follows:


Sec.  80.1502  What are the survey requirements related to gasoline-
ethanol blends?

* * * * *
    (b) * * *
    (3) * * *
    (iii) * * *
    (A) Samples collected at retail outlets shall be shipped the same 
day the samples are collected via ground service to the laboratory and 
analyzed for oxygenate content. Samples collected at a dispenser 
labeled E15 in any manner, or at a tank serving such a dispenser, shall 
also be analyzed for RVP during the high ozone season defined in Sec.  
80.27(a)(2)(ii) or any SIP approved or promulgated under Sec. Sec.  110 
or 172 of the Clean Air Act. Such analysis shall be completed within 10 
days after receipt of the sample in the laboratory. Nothing in this 
section shall be interpreted to require RVP testing of a sample from 
any dispenser or tank serving it unless the dispenser is labeled E15 in 
any manner.
* * * * *
    (iv) In the case of any test that yields a result that does not 
match the label affixed to the product (e.g., a sample greater than 15 
volume percent ethanol dispensed from a fuel dispenser labeled as 
``E15'' or a sample containing greater than 10 volume percent ethanol 
and not more than 15 volume percent ethanol dispensed from a fuel 
dispenser not labeled as ``E15''), or the RVP standard of Sec.  
80.27(a)(2), the independent survey association shall, within 24 hours 
after the laboratory has completed analysis of the sample, send 
notification of the test result as follows:
* * * * *
    (4) * * *
    (iv) * * *
    (B) In the case of any retail outlet from which a sample of 
gasoline was collected during a survey and determined to have an 
ethanol content that does not match the fuel dispenser label (e.g. a 
sample greater than 15 volume percent ethanol dispensed from a fuel 
dispenser labeled as ``E15'' or a sample with greater than 10 volume 
percent ethanol and not more than 15 volume percent ethanol dispensed 
from a fuel dispenser not labeled as ``E15'') or determined to have a 
dispenser containing fuel whose RVP does not comply with Sec.  
80.27(a)(2), that retail outlet shall be included in the subsequent 
survey.
* * * * *
    (v) * * *
    (A) The minimum number of samples to be included in the survey plan 
for each calendar year shall be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TP14JN13.003

Where:

n = minimum number of samples in a year-long survey series. However, 
in no case shall n be smaller than 7,500.
Z[alpha] = upper percentile point from the normal distribution to 
achieve a one-tailed 95% confidence level (5% [alpha]-level). Thus, 
Z[alpha] equals 1.645.
Z[beta] = upper percentile point to achieve 95% power. Thus, 
Z[beta] equals 1.645.
[phiv]1 = the maximum proportion of non-compliant stations for a 
region to be deemed compliant. In this test, the parameter needs to 
be 5% or greater, i.e., 5% or more of the stations, within a stratum 
such that the region is considered non-compliant. For this survey, 
[phiv]1 will be 5%.
[phiv]o= the underlying proportion of non-compliant stations in a 
sample. For the first survey plan, [phiv]o will be 2.3%. For 
subsequent survey plans, [phiv]o will be the average of the 
proportion of stations found to be non-compliant over the previous 
four surveys.
Stn = number of sampling strata. For purposes of this 
survey program, Stn equals 3.
Fa = adjustment factor for the number of extra samples 
required to compensate for collected samples that cannot be included 
in the survey, based on the

[[Page 36078]]

number of additional samples required during the previous four 
surveys. However, in no case shall the value of Fa be 
smaller than 1.1.
Fb = adjustment factor for the number of samples required 
to resample each retail outlet with test results exceeding the 
labeled amount (e.g. a sample greater than 15 volume percent ethanol 
dispensed from a fuel dispenser labeled as ``E15'', a sample with 
greater than 10 volume percent ethanol and not more than 15 volume 
percent ethanol dispensed from a fuel dispenser not labeled as 
``E15''), or a sample dispensed from a fuel dispenser labeled as 
``E15'' with greater than the applicable seasonal and geographic RVP 
pursuant to Sec.  80.27, based on the rate of resampling required 
during the previous four surveys. However, in no case shall the 
value of Fb be smaller than 1.1.
Sun = number of surveys per year. For purposes of this 
survey program, Sun equals 4.
* * * * *
    (c) * * *
    (4) The survey program plan must be sent to the following address: 
Director, Compliance Division, U.S. Environmental Protection Agency, 
1200 Pennsylvania Ave. NW., Mail Code 6506J, Washington, DC 20460.
* * * * *
    (6) The approving official for a survey plan under this section is 
the Director of the Compliance Division, Office of Transportation and 
Air Quality.
* * * * *
0
17. Section 80.1503 is amended by revising paragraphs (a)(1)(vi)(B)(3), 
(a)(1)(vi)(C)(2), adding paragraph (a)(1)(vi)(C)(3), and revising 
paragraphs (b)(1)(vi)(B) through (D).
    The revisions and additions read as follows:


Sec.  80.1503  What are the product transfer document requirements for 
gasoline-ethanol blends, gasolines, and conventional blendstocks for 
oxygenate blending subject to this subpart?

    (a) * * *
    (1) * * *
    (vi) * * *
    (B) * * *
    (3) ``The use of this blendstock/gasoline to manufacture a 
gasoline-ethanol blend containing anything other than between 9 and 10 
volume percent ethanol may cause a summertime RVP violation.''
    (C) * * *
    (2) The requirements in paragraph (a)(1) do not apply to 
reformulated gasoline blendstock for oxygenate blending, as defined in 
Sec.  80.2(kk), which is subject to the product transfer document 
requirements of Sec.  80.69 and Sec.  80.77.
    (3) Except for transfers to truck carriers, retailers, or wholesale 
purchaser-consumers, product codes may be used to convey the 
information required under paragraph (a)(1) of this section if such 
codes are clearly understood by each transferee.
    (b) * * *
    (1) * * *
    (vi) * * *
    (B) For gasoline containing less than 9 volume percent ethanol, the 
following statement: ``EX--Contains up to X% ethanol. The RVP does not 
exceed [fill in appropriate value] psi.'' The term X refers to the 
maximum volume percent ethanol present in the gasoline.
    (C) For gasoline containing between 9 and 10 volume percent ethanol 
(E10), the following statement: ``E10: Contains between 9 and 10 vol % 
ethanol. The RVP does not exceed [fill in appropriate value] psi. The 1 
psi RVP waiver applies to this gasoline. Do not mix with gasoline 
containing anything other than between 9 and 10 vol % ethanol.''
    (D) For gasoline containing greater than 10 volume percent and not 
more than 15 volume percent ethanol (E15), the following statement: 
``E15: Contains up to 15 vol % ethanol. The RVP does not exceed [fill 
in appropriate value] psi;'' or
* * * * *
0
18. Section 80.1504 is amended by revising paragraphs (a)(1), (a)(3), 
(e), and (g) to read as follows:


Sec.  80.1504  What acts are prohibited under this subpart?

* * * * *
    (a)(1) Sell, introduce, cause or permit the sale or introduction of 
gasoline containing greater than 10 volume percent ethanol (i.e., 
greater than E10) into any model year 2000 or older light-duty gasoline 
motor vehicle, any heavy-duty gasoline motor vehicle or engine, any 
highway or off-highway motorcycle, or any gasoline-powered nonroad 
engines, vehicles or equipment.
* * * * *
    (3) Notwithstanding paragraphs (a)(1) and (a)(2) of this section, 
no person shall be prohibited from manufacturing, selling, introducing, 
or causing or allowing the sale or introduction of gasoline containing 
greater than 10 volume percent ethanol into any flex-fuel vehicle.
* * * * *
    (e)(1) Improperly blend, or cause the improper blending of, ethanol 
into conventional blendstock for oxygenate blending, gasoline or 
gasoline already containing ethanol, in a manner inconsistent with the 
information on the product transfer document under Sec.  
80.1503(a)(1)(vi) or Sec.  80.1503(b)(1)(vi);
    (2) No person shall produce E10 by blending ethanol and gasoline in 
a manner designed to produce a fuel that contains less than 9.0 or more 
than 10.0 volume percent ethanol.
    (3) No person shall produce E15 by blending ethanol and gasoline in 
a manner designed to produce a fuel that contains less than 10.0 volume 
percent ethanol or more than 15.0 volume percent ethanol.
    (4) No person shall produce EX by blending ethanol and gasoline in 
a manner designed to produce a fuel that contains less than 9.0 volume 
percent ethanol.
* * * * *
    (g) For gasoline during the regulatory control periods, combine any 
gasoline-ethanol blend that qualifies for the 1 psi allowance under the 
special regulatory treatment as provided by Sec.  80.27(d) applicable 
to 9-10 volume percent gasoline-ethanol blends with any gasoline 
containing less than 9 volume percent ethanol or more than 10 volume 
percent ethanol up to a maximum of 15 volume percent ethanol.
* * * * *
0
19. Section 80.1508 is amended by revising paragraph (b) as follows:


Sec.  80.1508  What evidence may be used to determine compliance with 
the requirements of this subpart and liability for violations of this 
subpart?

* * * * *
    (b) Determinations of compliance with the requirements of this 
subpart and determinations of liability for any violation of this 
subpart may be based on information obtained from any source or 
location. Such information may include, but is not limited to, business 
records and commercial documents.
0
20. Section 80.1509 is added to read as follows:


Sec.  80.1509  Rounding a test result for purposes of this Subpart.

    The provisions of Section 80.9 apply for purposes of determining 
the ethanol content of a gasoline-ethanol blend under this subpart.

[FR Doc. 2013-12714 Filed 6-13-13; 8:45 am]
BILLING CODE 6560-50-P


