Document ID: EPA-HQ-OAR-2011-0147-0001
Agency: epa
Document Type: Proposed Rule
Title: Mandatory Reporting of Greenhouse Gases
Posted Date: 2011-08-04T04:00Z

[Federal Register Volume 76, Number 150 (Thursday, August 4, 2011)]
[Proposed Rules]
[Pages 47392-47421]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-18712]

[[Page 47391]]

Vol. 76

Thursday,

No. 150

August 4, 2011

Part IV

Environmental Protection Agency

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40 CFR Part 98

Mandatory Reporting of Greenhouse Gases; Proposed Rule

  Federal Register / Vol. 76, No. 150 / Thursday, August 4, 2011 / 
Proposed Rules  

[[Page 47392]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 98

[EPA-HQ-OAR-2011-0147; FRL-9443-1]
RIN 2060-AQ85

Mandatory Reporting of Greenhouse Gases

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: EPA is proposing to amend specific provisions in the Mandatory 
Reporting of Greenhouse Gases Rule to correct certain technical and 
editorial errors that have been identified since promulgation and to 
clarify or propose amendments to certain provisions that have been the 
subject of questions from reporting entities. These proposed changes 
include additional information to clarify compliance obligations, 
correct data reporting elements so they more closely conform to the 
information used to perform emission calculations, and make other 
corrections and amendments. EPA has received petitions for 
reconsideration on some of these subparts. EPA is still considering 
these petitions, and the issues raised in the petitions are not 
discussed or addressed in this action.

DATES: Comments. Comments must be received on or before September 19, 
2011.
    Public Hearing. EPA does not plan to conduct a public hearing 
unless requested. To request a hearing, please contact the person 
listed in the following FOR FURTHER INFORMATION CONTACT section by 
August 11, 2011. If requested, the hearing will be conducted on August 
19, 2011, in the Washington, DC area. EPA will provide further 
information about the hearing on its webpage if a hearing is requested.

ADDRESSES: You may submit your comments, identified by Docket ID No. 
EPA-HQ-OAR-2011-0147 by any of the following methods:
     Federal eRulemaking Portal: http://www.regulations.gov. 
Follow the online instructions for submitting comments.
     E-mail: MRR_Corrections@epa.gov. Include Docket ID No. 
EPA-HQ-OAR-2011-0147 [and/or RIN number] in the subject line of the 
message.
     Fax: (202) 566-9744.
     Mail: Environmental Protection Agency, EPA Docket Center 
(EPA/DC), Mailcode 2822T, Attention: Docket ID No. EPA-HQ-OAR-2011-
0147, 1200 Pennsylvania Avenue, NW., Washington, DC 20004.
     Hand/Courier Delivery: EPA Docket Center, Public Reading 
Room, EPA West Building, Room 3334, 1301 Constitution Avenue, NW., 
Washington, DC 20004. 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-
2011-0147, 2011 Technical Corrections, Clarifying and Other Amendments 
to Certain Provisions of the Mandatory Reporting of Greenhouse Gases 
Rule. EPA's policy is that all comments received will be included in 
the public docket without change and may be made available online at 
http://www.regulations.gov, including any personal information 
provided, unless the comment includes information claimed to be 
confidential business information (CBI) or other information whose 
disclosure is restricted by statute. Do not submit information that you 
consider to be CBI or otherwise protected through http://www.regulations.gov or e-mail. The http://www.regulations.gov Web site 
is an ``anonymous access'' system, which means EPA will not know your 
identity or contact information unless you provide it in the body of 
your comment. If you send an e-mail comment directly to EPA without 
going through http://www.regulations.gov your e-mail address will be 
automatically captured and included as part of the comment that is 
placed in the public docket and made available on the Internet. If you 
submit an electronic comment, EPA recommends that you include your name 
and other contact information in the body of your comment and with any 
disk or CD-ROM you submit. If EPA cannot read your comment due to 
technical difficulties and cannot contact you for clarification, EPA 
may not be able to consider your comment. Electronic files should avoid 
the use of special characters, any form of encryption, and be free of 
any defects or viruses.
    Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some 
information is not publicly available, e.g., CBI or other information 
whose disclosure is restricted by statute. Certain other material, such 
as copyrighted material, will be publicly available only in hard copy. 
Publicly available docket materials are available either electronically 
in http://www.regulations.gov or in hard copy at the Air Docket, EPA/
DC, EPA West Building, Room 3334, 1301 Constitution Ave., NW., 
Washington, DC. This Docket Facility is open from 8:30 a.m. to 4:30 
p.m., Monday through Friday, excluding legal holidays. The telephone 
number for the Public Reading Room is (202) 566-1744, and the telephone 
number for the Air Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Carole Cook, Climate Change Division, 
Office of Atmospheric Programs (MC-6207J), Environmental Protection 
Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone 
number: (202) 343-9263; fax number: (202) 343-2342; e-mail address: 
GHGReportingRule@epa.gov. For technical information, please go to the 
Greenhouse Gas Reporting Rule Program Web site http://www.epa.gov/climatechange/emissions/ghgrulemaking.html. To submit a question, 
select Rule Help Center, followed by Contact Us. To obtain information 
about the public hearing or to register to speak at the hearing, please 
go to http://www.epa.gov/climatechange/emissions/ghgrulemaking.html. 
Alternatively, contact Carole Cook at 202-343-9263.
    Worldwide Web (WWW). In addition to being available in the docket, 
an electronic copy of this proposal will also be available through the 
WWW. Following the Administrator's signature, a copy of this action 
will be posted on EPA's Greenhouse Gas Reporting Program Web site at 
http://www.epa.gov/climatechange/emissions/ghgrulemaking.html.

SUPPLEMENTARY INFORMATION:
    Additional Information on Submitting Comments: To expedite review 
of your comments by Agency staff, you are encouraged to send a separate 
copy of your comments, in addition to the copy you submit to the 
official docket, to Carole Cook, U.S. EPA, Office of Atmospheric 
Programs, Climate Change Division, Mail Code 6207-J, Washington, DC 
20460, telephone (202) 343-9263, e-mail address: 
GHGReportingRule@epa.gov.
    Regulated Entities. The Administrator determined that this action 
is subject to the provisions of Clean Air Act (CAA) section 307(d). See 
CAA section 307(d)(1)(V) (the provisions of section 307(d) apply to 
``such other actions as the Administrator may determine''). These are 
proposed amendments to existing regulations. If finalized, these 
amended regulations would affect owners or operators of certain 
industrial gas suppliers and direct emitters of GHGs. Regulated 
categories and examples of affected entities include those listed in 
Table 1 of this preamble:

[[Page 47393]]

           Table 1--Examples of Affected Entities by Category
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                                                  Examples of affected
             Category                 NAICS            facilities
------------------------------------------------------------------------
Petroleum and Natural Gas Systems.     486210  Pipeline transportation
                                                of natural gas.
                                       221210  Natural gas distribution
                                                facilities.
                                          211  Extractors of crude
                                                petroleum and natural
                                                gas.
                                       211112  Natural gas liquid
                                                extraction facilities.
Underground Coal Mines............     212113  Underground anthracite
                                                coal mining operations.
                                       212112  Underground bituminous
                                                coal mining operations.
Electrical Transmission and            221121  Electric bulk power
 Distribution Equipment Use.                    transmission and control
                                                facilities.
Industrial Wastewater Treatment...     322110  Pulp mills.
                                       322121  Paper mills.
                                       322122  Newsprint mills
                                       322130  Paperboard mills.
                                       311611  Meat processing
                                                facilities.
                                       311411  Frozen fruit, juice, and
                                                vegetable manufacturing
                                                facilities.
                                       311421  Fruit and vegetable
                                                canning facilities.
                                       325193  Ethanol manufacturing
                                                facilities.
                                       324110  Petroleum refineries.
Suppliers of Industrial GHGs......     325120  Industrial gas production
                                                facilities.
Geologic Sequestration of Carbon          N/A  CO2 geologic
 Dioxide.                                       sequestration projects
Industrial Waste Landfills........     562212  Solid waste landfills.
                                       322110  Pulp mills.
                                       322121  Paper mills.
                                       322122  Newsprint mills.
                                       322130  Paperboard mills.
                                       311611  Meat processing
                                                facilities.
                                       311411  Frozen fruit, juice, and
                                                vegetable manufacturing
                                                facilities.
                                       311421  Fruit and vegetable
                                                canning facilities.
                                       221320  Sewage treatment
                                                facilities.
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    Table 1 of this preamble is not intended to be exhaustive, but 
rather lists the types of facilities or suppliers that EPA is now aware 
could be potentially affected by the reporting requirements. Other 
types of facilities and suppliers than those listed in the table could 
also be subject to reporting requirements. To determine whether you are 
affected by this action, you should carefully examine the applicability 
criteria found in 40 CFR part 98, subpart A or the relevant criteria in 
the sections related to suppliers and direct emitters of GHGs. If you 
have questions regarding the applicability of this action to a 
particular facility or supplier, consult the person listed in the 
preceding FOR FURTHER INFORMATION CONTACT Section.
    Acronyms and Abbreviations. The following acronyms and 
abbreviations are used in this document.

acf actual cubic feet.
AGR acid gas removal.
ASTM American Society for Testing and Materials.
BAMM best available monitoring methods.
CAA Clean Air Act.
CBI confidential business information.
CEMS continuous emissions monitoring system.
CFC chlorofluorocarbon.
CFR Code of Federal Regulations.
CH4 methane.
CO2 carbon dioxide.
DOC degradable organic carbon.
EF emission factor.
e-GGRT electronic-GHG Reporting Tool.
EPA U.S. Environmental Protection Agency.
FR Federal Register.
GHG greenhouse gas.
GHGRP Greenhouse Gas Reporting Program.
HCFC hydrochlorofluorocarbon.
kg kilograms.
kg/ft\3\ kilograms per cubic foot.
mcf methane correction factor.
MMscf million standard cubic feet.
MRV monitoring, reporting and verification.
MSHA Mine Safety and Health Administration.
MtCO2e metric tons carbon dioxide equivalent.
N2O nitrous oxide.
NAICS North American Industry Classification System.
NOAA National Oceanic and Atmospheric Administration.
NTTAA National Technology Transfer and Advancement Act.
OMB Office of Management and Budget.
PFCs perfluorocarbons.
psia pounds per square inch absolute.
RFA Regulatory Flexibility Act.
SF6 sulfur hexafluoride.
U.S. United States.
UMRA Unfunded Mandates Reform Act of 1995.

Table of Contents

I. Background
    A. How is this preamble organized?
    B. Background on This Action
    C. Legal Authority
    D. How would these amendments apply to 2012 reports?
II. Technical Corrections and Other Amendments
    A. Subpart A--General Provisions
    B. Subpart W--Petroleum and Natural Gas Systems
    C. Subpart FF--Underground Coal Mines
    D. Subpart II--Industrial Wastewater Treatment
    E. Subpart OO--Suppliers of Industrial Greenhouse Gases
    F. Subpart RR--Geologic Sequestration of Carbon Dioxide
    G. Subpart TT--Industrial Waste Landfills
III. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and 
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act (UMRA)
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination with 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children from 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions that Significantly Affect 
Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions to Address 
Environmental Justice in Minority Populations and Low-Income 
Populations

[[Page 47394]]

I. Background

A. How is this preamble organized?

    The first section of this preamble contains the basic background 
information about the origin of these proposed rule amendments and 
request for public comment. This section also discusses EPA's use of 
our legal authority under the Clean Air Act to collect data under the 
Mandatory Reporting of Greenhouse Gases (GHG reporting) rule.
    The second section of this preamble describes in detail the changes 
that are being proposed to correct technical errors, to provide 
clarification, or propose amendments to address implementation issues 
identified by EPA and others. This section also presents EPA's 
rationale for the proposed changes and identifies issues on which EPA 
is particularly interested in receiving public comments.
    Finally, the last (third) section of the preamble discusses the 
various statutory and executive order requirements applicable to this 
proposed rulemaking.

B. Background on This Action

    The 2009 final GHG reporting rule (2009 final rule) was signed by 
EPA Administrator Lisa Jackson on September 22, 2009 and published in 
the Federal Register on October 30, 2009 (74 FR 56260, October 30, 
2009). The 2009 final rule, which became effective on December 29, 
2009, includes reporting of GHGs from various facilities and suppliers, 
consistent with the 2008 Consolidated Appropriations Act.\1\ Subsequent 
notices were published in 2010 finalizing the requirements for subparts 
FF, II, and TT (75 FR 39736, July 12, 2010), subpart W (75 FR 74458, 
November 30, 2010), subpart DD (75 FR 74774, December 1, 2010) and 
subpart RR (75 FR 75060, December 1, 2010). Subpart OO, which was 
promulgated as part of the 2009 final rule was also revised in 2010 (75 
FR 79092, December 17, 2010). The source categories in 40 CFR part 98 
cover approximately 85-90 percent of U.S. GHG emissions through 
reporting by direct emitters, as well as suppliers of certain products 
that would result in GHG emission when released, used, or oxidized, and 
those that geologically sequester or otherwise inject carbon dioxide 
(CO2) underground.
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    \1\ Consolidated Appropriations Act, 2008, Public Law 110-161, 
121 Stat. 1844, 2128.
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C. Legal Authority

    EPA is proposing these rule amendments under its existing CAA 
authority, specifically authorities provided in CAA section 114.
    As stated in the preamble to the 2009 final rule (74 FR 56260) and 
the Response to Comments on the Proposed Rule, Volume 9, Legal Issues, 
CAA section 114 provides EPA broad authority to require the information 
proposed to be gathered by this rule because such data would inform and 
are relevant to EPA's carrying out a wide variety of CAA provisions. As 
discussed in the preamble to the initial proposed rule (74 FR 16448, 
April 10, 2009), CAA section 114(a)(1) authorizes the Administrator to 
require emissions sources, persons subject to the CAA, manufacturers of 
control or process equipment, or persons whom the Administrator 
believes may have necessary information to monitor and report emissions 
and provide such other information the Administrator requests for the 
purposes of carrying out any provision of the CAA. For further 
information about EPA's legal authority, see the preambles to the 2009 
proposed and final rules and EPA's Response to Comments, Volume 9.

D. How would these amendments apply to 2012 reports?

    EPA is planning to address the comments on these proposed 
amendments and publish the final amendments before the end of 2011. 
Therefore, reporters would be expected to calculate emissions and other 
relevant data for the reports that are submitted in 2012 using 40 CFR 
part 98 as amended by this proposed action. We have determined that it 
is feasible for the sources to implement these changes for the 2011 
reporting year because the revisions primarily provide additional 
clarifications regarding the existing regulatory requirements, do not 
change the type of information that must be collected, and do not 
materially affect how emissions are calculated.
    For example, EPA is proposing several technical clarifications and 
amendments to subpart A to address issues raised by reporters through 
questions to the hotline in late 2010 and early 2011, as well as those 
identified by EPA. For additional background information on the 
questions raised, please refer to the Technical Support Document for 
the 2011 Technical Corrections, Clarifying and Other Amendments to 
Certain Provisions of the Mandatory Reporting of Greenhouse Gases Rule 
proposal available in the docket to this rulemaking (EPA-HQ-OAR-2011-
0147). For instance, we are proposing to change the threshold for 
underground coal mines to include only those that liberate 36,500,000 
actual cubic feet (acf) of methane (CH4) or more per year 
(equivalent to 100,000 acf of CH4 or more per day). If the 
current regulatory threshold is retained, all mines that are currently 
subject to quarterly or more frequent sampling by Mine Safety and 
Health Administration (MSHA) would be required to report. Given that 
the original requirements were based on an incorrect assumption 
regarding the number of mines that MSHA samples, we are proposing a new 
threshold that will remove reporting requirements for approximately 500 
mines (see relevant discussion in Section II.C of this preamble). We 
are also proposing provisions to clarify the time period during which 
information must be submitted to EPA and to clarify which information 
may be submitted through the electronic Greenhouse Gas Reporting Tool 
(e-GGRT) and which must be mailed to the Director of the Climate Change 
Division. We are also proposing a revision to the definition of 
``supplier'' to be consistent with changes made to the rule during 
2010. These changes impose no additional burden for facilities, and 
could be readily implemented for the 2011 reporting year.
    Many proposed revisions provide additional information to provide 
clarity on existing requirements. For example, in subpart W (Petroleum 
and Natural Gas Systems) we are providing additional clarity on the 
methodological options for calculating emissions from acid gas removal 
units and emissions from well venting for liquids unloading. In subpart 
FF (Underground Coal Mines) we are proposing to clarify use of MSHA 
data to calculate emissions. While MSHA data may be used to collect 
data for volume and concentration of methane, it does not provide 
temperature and pressure data; therefore, we are proposing that 
measurements of temperature must be made at the same time as MSHA 
measurements for volume and concentration of methane and that for 
pressure, facilities must use either a measured value or the average 
annual barometric pressure from the nearest National Oceanic and 
Atmospheric Administration (NOAA) weather service station. This 
proposed clarification is consistent with clarifications EPA has issued 
in response to industry questions and does not change the rule 
requirements for facilities collecting data in 2011 because the 
requirements to collect temperature and pressure data were already 
clear in 40 CFR 98.324(b)(1). In subpart RR, clarifying text is 
proposed in 40 CFR 98.443(d) to ensure that facilities account for 
CO2

[[Page 47395]]

entrained in produced fluids from oil or gas production wells or from 
other fluid wells that are not processed through a gas-liquid 
separator. Although we intended that CO2 content in all 
produced liquids would be determined (see Section II.B.4 of the 
preamble to the final subpart RR rule (75 FR 75065, December 1, 2010)), 
the text in 40 CFR 98.443(d) and associated equations were based on 
measurements that did not include fluids removed without the use of a 
separator, such as water removed for pressure relief. Therefore, the 
clarifying text does not change the rule requirements for facilities 
collecting data in 2011.
    Other proposed amendments provide additional clarity to the data 
reporting elements. For example, in subpart II (Industrial Wastewater 
Treatment) we are proposing to clarify what is meant by weekly sampling 
in 40 CFR 98.353(c) and (d); the proposed revisions would clarify that 
reporters that sample only once per week must sample more than three 
days apart.
    For some subparts, we are proposing amendments that would provide 
additional flexibility to the sources. Thus, while they would be free 
to use the amended regulations once final, facilities are not required 
to follow the amendments for 2011 data collection. For example, in 
subpart TT (Industrial Waste Landfills), facilities are provided an 
additional approach for determining the volatile solids concentration 
or the waste-specific degradable organic carbon (DOC) values for 
historically disposed streams. The July 12, 2010 final rule had no 
provisions by which waste streams that were not disposed of in the 
first reporting year could be assessed. These waste streams were 
required to use the default DOC values, which have a high degree of 
uncertainty. The proposed revision allows owners and operators of 
industrial waste landfills to develop more accurate values for volatile 
solids concentration and site-specific DOC. With these proposed 
amendments, these facilities would have the option, but not be 
required, to use the newly proposed option for the reports submitted to 
EPA in 2012 and thereafter.
    EPA is also proposing corrections to terms and definitions in 
certain equations. For example, in subpart TT (Industrial Waste 
Landfill), we are proposing to delete Equation TT-7 and amend Equation 
TT-8, which were incorrectly based on the assumption that the volatile 
solids concentration was expected to have units of mass of volatile 
solids per mass of (wet) waste. We are correcting these equations per 
Standard Method 2540G ``Total, Fixed, and Volatile Solids in Solid and 
Semisolid Samples,'' in which the volatile solids concentration is 
determined on a dry basis. These clarifications do not result in 
additional requirements; therefore, EPA has concluded that reporters 
subject to the subparts that would be amended by this proposed action 
can follow the rule, as amended, in submitting their reports in 2012 
and thereafter.
    Finally, EPA is proposing other technical corrections (e.g., 
correcting cross references) that have no impact on facilities' data 
collection efforts in 2011.
    In summary, these amendments would not require any additional 
monitoring or information collection above what was already included in 
40 CFR part 98. Therefore, we expect that sources can use the same 
information that they have been collecting under 40 CFR part 98 for 
each subpart to calculate and report GHG emissions for 2011 and submit 
reports in 2012 under the amended subparts.
    EPA generally seeks comment on the conclusion that it is 
appropriate to implement these amendments and incorporate the 
requirements in the data reported to EPA in 2012. Further, we seek 
comment on whether there are specific subparts and specific proposed 
changes where this timeline may not be feasible or appropriate due to 
the nature of the proposed changes or the way in which data have been 
collected thus far in 2011. We request that commenters provide specific 
examples of how the proposed implementation schedule would or would not 
work.

II. Technical Corrections and Other Amendments

    Following promulgation of subparts A and OO on October 30, 2009, 
subparts FF, II, and TT on July 12, 2010, subpart W on November 30, 
2010, and subparts DD and RR on December 1, 2010, EPA has identified 
errors in the regulatory language that we are now proposing to correct. 
These errors were identified as a result of working with affected 
industries to implement these subparts. We have also identified certain 
rule provisions that should be amended to provide greater clarity. The 
amendments we are now proposing include the following types of changes:
     Changes to correct cross references within and between 
subparts.
     Additional information to better or more fully understand 
compliance obligations in a specific provision, such as the reference 
to a standardized method that must be followed.
     Amendments to certain equations to better reflect actual 
operating conditions.
     Corrections to terms and definitions in certain equations.
     Corrections to data reporting requirements so that they 
more closely conform to the information used to perform emission 
calculations.
     Other amendments related to certain issues identified as a 
result of working with the affected sources during rule implementation 
and outreach.
    We are seeking public comment only on the issues specifically 
identified in this notice for the identified subparts. We will not 
respond to any comments addressing other aspects of 40 CFR part 98.

A. Subpart A--General Provisions

    EPA is proposing several technical clarifications and amendments to 
subpart A to address issues raised by reporters and identified by EPA 
during the first year of implementation of the GHG Reporting Program 
(GHGRP), as well as to clarify terminology to ensure consistency across 
all subparts. In addition, a number of minor amendments are proposed to 
ensure that the General Provisions appropriately reflect the 
incorporation of the additional subparts into the GHGRP that were 
finalized in 2010.
    Threshold for Electrical Transmission and Distribution Equipment 
Use. We are proposing to amend Table A-3 in the General Provisions to 
clarify applicability of the rule for Electrical Transmission and 
Distribution Equipment Use (subpart DD). The final subpart DD rule 
(December 1, 2010; 75 FR 74774) specifies at Sec.  98.301 that 
reporting is required for an electric power system only if the total 
nameplate capacity of SF6 and PFC containing equipment 
located within the electric power system, when added to the total 
nameplate capacity of SF6 and PFC containing equipment that 
is not located within the electric power system but is under common 
ownership or control, exceeds 17,820 pounds. That section of the rule 
also specifies that a facility other than an electric power system that 
is subject to part 98 because of emissions from another source category 
is only required to report emissions under subpart DD if the total 
nameplate capacity of SF6 and PFC containing equipment 
located within that facility exceeds 17,820 pounds. The final rule, 
however, does not include the 17,820 pound capacity threshold in Table 
A-3. Some potential reporters have questioned if this omission means 
that all facilities with electric power equipment must submit an annual 
report, even if they are below the capacity threshold and are not

[[Page 47396]]

otherwise required to report under any other provisions of part 98. 
This interpretation is clearly not the intent of the rule. The 
regulatory text in the final rule can and should be interpreted to mean 
that a facility is required to submit an annual report only if the 
capacity threshold is exceeded. This interpretation is clear from the 
preamble to the proposal (74 FR 16609) as well as the final rule (75 FR 
74774)). However, we are proposing to revise Table A-3 to insert the 
capacity threshold language of Sec.  98.301 to make the rule clearer 
and less subject to misinterpretation. Because the test for whether a 
facility meets the numerical threshold differs depending on the type of 
facility, we are including a reference to Sec.  98.301. Therefore, we 
are revising the Table A-3 entry for subpart DD to read as follows: 
Electrical transmission and distribution use at facilities where the 
total nameplate capacity of SF6 and PFC containing equipment 
exceeds 17,820 pounds, as determined under Sec.  98.301 (subpart DD).
    Threshold for Underground Coal Mines. We are proposing to change 
the threshold for underground coal mines to include only those that 
have ventilation emissions of 36,500,000 acf of CH4 or more 
per year. For a full description of this proposed change, please refer 
to the relevant discussion under subpart FF of this action.
    Computation of Time. EPA is proposing to add a provision to 40 CFR 
98.3(b) to allow information, including but not limited to, the annual 
GHG report and any subsequent re-submissions, the certificate of 
representation, and requests to use best available monitoring methods, 
to be submitted to EPA on the next business day in the event that a 
regulatory deadline falls on a weekend or a Federal holiday. The 
proposed language is consistent with a similar provision under the Acid 
Rain Program (40 CFR 72.11) and will provide all reasonable 
flexibilities for submitting data without compromising data quality.
    2012 Reporting Deadline. We are proposing a one-time extension of 
the 2012 reporting deadline for facilities and suppliers subject to 
source categories for which data collection began January 1, 2011 
(referred to below as the ``new 2011 reporting year source 
categories'').\2\ A deadline extension from March 31, 2012 to September 
28, 2012 would apply only to reporting of data elements under the 
following source categories: Electronics Manufacturing (subpart I), 
Fluorinated Gas Production (subpart L), Magnesium Production (subpart 
T), Petroleum and Natural Gas Systems (subpart W), Use of Electric 
Transmission and Distribution Equipment (subpart DD), Underground Coal 
Mines (subpart FF), Industrial Wastewater Treatment (subpart II), 
Imports and Exports of Equipment Pre-charged with Fluorinated GHGs or 
Containing Fluorinated GHGs in Closed-cell Foams (subpart QQ), Geologic 
Sequestration of Carbon Dioxide (subpart RR), Manufacture of Electric 
Transmission and Distribution (subpart SS), Industrial Waste Landfills 
(subpart TT), and Injection of Carbon Dioxide (subpart UU).
---------------------------------------------------------------------------

    \2\ There was a separate one-time extension of the reporting 
deadline for facilities and suppliers first required to report GHG 
information to EPA in 2011, for data collected during 2010 (76 FR 
14812). The deadline extension in this proposal only applies to the 
reporting of information from those source categories for which data 
collection began in 2011 and for which data are to be reported in 
2012.
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    All facilities and suppliers subject to the GHGRP, including 
facilities and suppliers that include the source categories listed 
above, would still be required to report their GHG information for all 
other subparts by March 31, 2012. For example, a facility subject to 
report GHG information under subparts C, W, and PP would still be 
required to report GHG information for subparts C and PP by March 31, 
2012, but would not be required to submit the required data reporting 
elements under subpart W until September 28, 2012.
    We are proposing this change to the 2012 reporting deadline for the 
new 2011 reporting year source categories in order to allow sufficient 
time for development, and more importantly stakeholder testing, of the 
electronic-GHG Reporting Tool (e-GGRT). Stakeholder testing provides an 
opportunity for EPA to receive feedback from reporters and other 
interested stakeholders to enable EPA to test the effectiveness of the 
user interface of e-GGRT, correct any problems in advance of the 
reporting deadline, and ultimately ensure that the data received under 
the program are of the highest quality. Stakeholder testing of the 
electronic reporting tool for the new 2011 reporting year source 
categories is particularly important given the large number of 
reporters affected by these new categories (more than one quarter of 
all reporters are estimated to be required to report under these new 
subparts).
    Based on the discussion above, we are seeking comment on whether a 
six-month extension of the 2012 reporting deadline for the new 2011 
reporting year source categories to September 28, 2012, would be 
appropriate. Facilities and suppliers subject to the rule would still 
be required to report all other required data reporting elements by 
March 31, 2012, but would not report information related to the new 
2011 reporting year source categories until September 28, 2012.
    Reporting on use of Best Available Monitoring Methods (BAMM). We 
are proposing to amend 40 CFR 98.3(c)(7) to remove the phrase 
``according to paragraph (d) of this section'' thereby requiring all 
facilities and suppliers that use BAMM to provide a brief description 
of each ``best available monitoring method'' used, the parameter 
measured using the method, and the time period during which the ``best 
available monitoring method'' was used, if applicable. This reporting 
requirement was applicable to all facilities and suppliers using BAMM 
in the 2009 final rule. Most of the subparts promulgated in 2010 
(subparts T, DD, FF, II, QQ, RR, SS, TT, and UU) directly referred back 
to the procedures in 40 CFR 98.3(d), and therefore the requirement to 
report basic information on BAMM is required. Through this amendment, 
we are clarifying that this basic information must be reported for all 
subparts, including subparts L (Fluorinated Gas Production) and W 
(Petroleum and Natural Gas Systems). This does not impact the 
requirements of subpart I (Electronics Manufacturing), which already 
directly include this reporting requirement in the data reporting 
requirements of that subpart.
Definitions
    Blowdown vent stack. We are proposing to amend the definition of 
blowdown vent stack emissions to add the phrase ``emissions from 
emergency events are not included.'' EPA is proposing to make this 
change to promote better consistency with provisions in subpart C, 
which exempted emissions from emergency generators and equipment from 
being included in the GHG emissions calculations.
    Supplier. Based on changes made to the rule during 2010, the 
definition of supplier does not adequately represent the breadth of 
subparts covered under the rule. EPA is proposing to change the 
definition of supplier in 40 CFR 98.6 so it specifically refers to 
those source categories listed in Table A-5 to subpart A of part 98, 
and is as described in the definition of the source category in the 
applicable subparts.
    The proposed amendment is necessary because suppliers are currently 
defined as suppliers of fossil fuels and industrial GHGs. However, 
during 2010, EPA changed the definition of fossil fuels in a rulemaking 
(75 FR 79092) that could be wrongly

[[Page 47397]]

interpreted to exclude some suppliers that are clearly subject to the 
rule. In the 2009 final rule, fossil fuel was defined in 40 CFR 98.6 as 
meaning natural gas, petroleum, coal, or any form of solid, liquid, or 
gaseous fuel derived from such material, including for example, 
consumer products that are derived from such materials and are 
combusted. Using this definition, suppliers of fossil fuel-based 
products were covered by subparts MM and NN regardless of the product 
end-use. This interpretation is clear from the preamble to the 2009 
final rule (74 FR 56260). However, in the subsequent rulemaking (75 FR 
79092) EPA modified the definition of fossil fuel to read natural gas, 
petroleum, coal, or any form of solid, liquid, or gaseous fuel derived 
from such material, for purpose of creating useful heat. We were clear 
in the preamble to that final rule that the change was not intended to 
have any impact on coverage of GHGs under the GHGRP (see 75 FR 79104). 
Nevertheless, referring to only suppliers of fossil fuels could now 
wrongly be interpreted so as to exclude some coverage under subparts MM 
and NN.
    In addition, we added a new source category to the rule called 
Importers and Exporters of Fluorinated GHGs Contained in Pre-charged 
Equipment or Closed-cell Foams (subpart QQ, 75 FR 74774). Although one 
could interpret the existing definition to include suppliers of 
fluorinated GHGs in bulk and in products, the proposed amendment 
further clarifies that suppliers include all the relevant source 
categories included in Table A-5.
    We are also proposing a harmonizing change in 40 CFR 98.1(a)(1) to 
remove the terms ``fossil fuel'' and ``industrial greenhouse gas'' 
before the term ``supplier.''
    Submission of reports and other information to EPA. There were some 
questions raised in the 2009 final rule about where certain 
communications should be directed, whether electronically through the 
electronic greenhouse gas reporting tool (40 CFR 98.5) or through the 
mail with an attention to the Director of the Climate Change Division 
(40 CFR 98.9). 40 CFR 98.5 reads that each GHG report and certificate 
of representation for a facility or supplier must be submitted 
electronically in a format specified by the Administrator. 40 CFR 98.9 
was intended to provide a mailing address for all other communications 
under the program, however, the regulatory language indicated that the 
mailing address was for all requests, notifications, and communications 
to the Administrator other than submittal of the annual GHG report. 
This raised a question as to whether the certificate of representation 
could be submitted through the mail.
    To address this potential source of confusion, we are clarifying 
that the annual GHG report, the certificate of representation, and all 
other requests, notifications, or communications that can be submitted 
through e-GGRT, must be submitted through e-GGRT. All other requests, 
notifications, or communications to the Administrator pursuant to this 
part shall be submitted through the mail to the Director of the Climate 
Change Division.
    Other Technical Corrections. We are proposing to amend 40 CFR 
98.2(d) and (e) to remove references to paragraphs 40 CFR 98.2(a)(4)(i) 
and (a)(4)(ii), respectively, which were removed when we finalized 
amendments during 2010 to consolidate the lists of source categories 
covered into tables. The correct references for both paragraphs should 
have been to 40 CFR 98.2(a)(4). In those same paragraphs we are 
clarifying that the applicability determination for importers should be 
assessed separately from the applicability determination for exporters. 
In other words, the emissions from the quantity of GHGs imported should 
be calculated for comparison to the 25,000 metric tons CO2e 
threshold and separately the quantity of GHGs exported should be 
calculated for comparison to the 25,000 metric tons CO2e. 
Based on questions received from reporters during the 2010 reporting 
year, it was unclear if the quantity of imports and exports should be 
assessed separately, added together, or the net imports minus exports 
calculated for comparison to the threshold. Finally, we are clarifying 
in Table A-5 that coverage and the applicability determination for 
importers and exporters under subpart MM includes suppliers of natural 
gas liquids in addition to suppliers of petroleum products. The 
inclusion of natural gas liquids suppliers was clear in 40 CFR 
98.2(a)(4) and subpart MM (40 CFR 98.390), however, it was 
inadvertently omitted from Table A-5.
    We are proposing to amend 40 CFR 98.2(i)(3) to add a date by which 
owners and operators must notify EPA that they no longer need to submit 
an annual GHG report because their operations have changed such that 
all applicable GHG-emitting processes and operations cease to operate. 
40 CFR 98.2(i) provides three instances where facilities or suppliers 
no longer need to report to EPA. In instances where facilities or 
suppliers report less than 25,000 metric tons carbon dioxide equivalent 
(mtCO2e) per year for 5 years, or less than 15,000 
mtCO2e for 3 years, they are required to notify EPA by March 
31 of the following year that they are no longer to report for the year 
after the year in which these conditions have been met. Similarly, the 
owner or operator is exempt from reporting in the years following the 
year in which cessation of such operations occurs, provided that the 
owner or operator submits a notification to the Administrator. However, 
the rule does not provide a date by which such notification be made. 
EPA is proposing that, similar to the requirements in 40 CFR 98.2(i)(1) 
and (i)(2), owners or operators notify EPA by March 31 of the year 
following the reporting year in which such conditions have been met.
    In 40 CFR 98.3(c)(10) and in the definition of United State parent 
company(s) in 40 CFR 98.6, we are proposing to replace the term 
``reporting entity'' with the term ``facility or supplier.'' Reporting 
entity has not typically been used in the GHGRP and for consistency 
across the individual subparts of the rule, we are proposing to use the 
term ``facility or supplier'' which in turn clarifies that the 
obligation is on the owner or operator of any such facility or 
supplier. This is consistent with the preamble to the rule that amended 
40 CFR part 98 with 40 CFR 98.3(c)(10), in which it is clear that 
``reporting entity'' means ``facility or supplier'' (see, for example, 
75 FR 57676).
    To address several requests for clarification received on the 
recordkeeping requirements, we are proposing to clarify that the 3-year 
requirement for retention of records starts from the date of submission 
of the annual GHG report for the reporting year in which the record was 
generated. This is as opposed to having the 3-year clock start on the 
day that the record was generated. The proposal, which is consistent 
with the Acid Rain Program, is in recognition of the fact that common 
practice is to retain all of the records for a single reporting year in 
a readily retrievable format, regardless if the record was generated on 
January 1st or December 31st of that reporting year. We are therefore 
proposing that the records be retained for 3 years from the data of 
submission of the applicable annual GHG report.
    In 40 CFR 98.3(c)(5)(ii) we are proposing to replace the use of the 
term ``emissions'' with ``quantities'' when referring to the 
information reported under industrial GHG suppliers. This is consistent 
with efforts throughout the GHG Reporting Program to clarify that 
information reported for supplier categories do not necessarily reflect

[[Page 47398]]

emissions to the atmosphere, but rather ``quantities'' that may be 
released if all of the supply were combusted or released.
    We are also proposing to correct an incorrect cross reference in 40 
CFR 98.4(m)(4) from (m)(2)(iv)(A) to (m)(2)(v)(A).

B. Subpart W--Petroleum and Natural Gas Systems

    EPA is proposing several technical clarifications and amendments to 
subpart W to address issues raised during the first year of 
promulgation of the rule, as well as clarifications to specified 
provisions in the rule to ensure consistency across all subparts. In 
addition, several technical corrections are proposed to clarify 
provisions that were either erroneous or unclear to reporters.
    Definitions. EPA is proposing to amend the definition for gas well 
in 40 CFR 98.238. The definition of gas well that was finalized in the 
rule, posed the question of whether or not gas wells that included any 
hydrocarbon condensate were also considered gas wells. The amendment 
clarifies the definition for gas well by stating that it includes gas 
wells that also produce natural gas including condensate.
    Threshold Clarifications. EPA is broadly including clarification to 
several throughput thresholds in subpart W in response to 
clarifications sought by reporters subject to the rule. We are 
proposing to amend the threshold in the definition of the source 
category for the onshore natural gas processing industry segment in 40 
CFR 98.230(a)(2). This definition includes a threshold provision, which 
states that all processing facilities that do not fractionate with a 
throughput per day of 25 million standard cubic feet (MMscf) or greater 
are covered under the rule. Without a clarification on how the 25 MMscf 
per day is to be determined, this provision resulted in confusion for 
reporters. Thus, we propose to amend the definition to state that the 
25 MMscf per day throughput threshold is based on an annual average 
throughput that the reporter would use to determine if they are covered 
under this definition.
    Similarly, we are proposing to clarify that the throughput 
threshold for glycol dehydrators (40 CFR 98.233(e)(1) and (e)(2)) and 
onshore production storage tanks (40 CFR 98.233(j)(1),(j)(2),(j)(3) and 
(j)(4)) are also based on annual average throughput. These proposed 
amendments are described further in the Calculating Greenhouse Gas 
Emissions section below.
    Greenhouse Gases to Report. We are proposing to clarify in 40 CFR 
98.232(d) that the greenhouse gases to be reported under the natural 
gas processing industry segment include nitrous oxide (N2O) 
emissions and not just CO2 and CH4 emissions. 
This proposed amendment will make 40 CFR 98.232(d) consistent with 
other provisions in the rule related to calculating GHG emissions from 
flare stacks. The rule in 40 CFR 98.232(j) clearly states that you are 
required to report CO2, CH4 and N2O 
emissions for all flare stacks in all applicable industry segments and 
flare stacks are included to be reported in natural gas processing 
facilities (98.232(d)(6)). Finally, the calculation methodology for 
flare stack emissions includes the method for quantifying 
N2O emissions from these stacks (See section 98.233(n)(8)). 
This proposed clarification avoids confusion as to whether 
N2O emissions, which typically result from flaring 
activities, would need to be reported under this industry segment.
    In addition, we are proposing to clarify in 40 CFR 98.232(i) that 
CO2 and CH4 emissions are to be reported from the 
natural gas distribution industry segment. This clarification was 
necessary to ensure that the affected reporters are aware that these 
GHG's are to be reported from this industry segment.
    Calculating Greenhouse Gas Emissions. We are proposing several 
clarifications, corrections, and amendments throughout 40 CFR 98.233.
    First, we are proposing to amend the definition for GHGi 
of Equation W-1 in 40 CFR 98.233(a) which is used for calculating GHG 
emissions from natural gas pneumatic device venting. In specific, the 
definition for the parameter GHGi in Equation W-1 was 
incorrect in that it inferred that it applied to facilities listed in 
40 CFR 98.230(a)(3) through (a)(8) when it actually only applies to the 
onshore production, natural gas transmission, and underground natural 
gas storage industry segments of subpart W. In addition, we are 
proposing to further amend the definition for parameter GHGi 
in Equation W-1 to clarify that GHGi should equal 0.952 for 
CH4 and 1 X 10-3 for CO2 for facilities in 40 CFR 
98.230(a)(4) and (a)(5). Previously, this equation did not include any 
clarification of what the parameter GHGi would be for 
methane and carbon dioxide and as a result confusion arose as to what 
values should be used for the natural gas transmission and underground 
natural gas storage industry segments. Further, for both Equation W-1, 
and W-2, of 40 CFR 98.233, we are proposing to amend the definition for 
the parameter GHGi to include a reference to 40 CFR 
98.233(u)(2)(i) to clarify how and at what frequency GHGi is 
to be determined for produced natural gas from the onshore production 
industry segment. We are proposing these amendments to Equations W-1 
and W-2, to clarify specific aspects of the parameter GHGi 
and how it applies to applicable industry segments and how it is to be 
determined to address lack of clarity on these aspects of the equation.
    Next, we are proposing amendments to 40 CFR 98.233(d) to clarify 
how the four different methods are to be used for determining GHG 
emissions from acid gas removal (AGR) vents. In many cases a reporter 
may have both a continuous emissions monitoring system (CEMS) or a vent 
meter available at their facility, and when reviewing the methods in 40 
CFR 98.233(d) in the final rule, the reporter would not be able to 
easily determine which method would apply when certain technologies are 
available. Thus, we are proposing to amend 40 CFR 98.233(d)(2), (3) and 
(4) to clarify that if a facility has a vent meter but no CEMs 
available for determining the CO2 emissions from AGR units 
then they would use Calculation Methodology 2 and if a facility has 
neither a CEMs in place or a vent meter in place, they have the option 
of using either Calculation Methodology 3 or 4 of 40 CFR 98.233(d).
    Next, we are proposing several amendments to 40 CFR 98.233(e) for 
calculating emissions from dehydrator vents. First, we are proposing to 
include minor non-substantive revisions to the citations in 40 CFR 
98.233(e) and (e)(1)(xi)(C). Next we are proposing to fix an erroneous 
citation in 40 CFR 98.233(e)(1)(xi) to correctly reference 40 CFR 
98.233(e)(1)(xi) instead of 40 CFR 98.233(e)(2)(xi). Finally, we are 
proposing to amend 40 CFR 98.233(e)(1) and (e)(2) to clarify that the 
throughput threshold of 0.4 million standard cubic feet per day is to 
be determined using an annual average daily throughput. We are 
proposing to include this particular amendment to clarify to reporters 
how this throughput threshold is to be determined.
    We are proposing to amend engineering Equation W-8, which is used 
to calculate emissions from well venting for liquids unloading. First, 
we are proposing to amend the first sentence in 40 CFR 98.233(f)(2) to 
state that Calculation Methodology 2 is to be used to calculate the 
total emissions for well venting for liquids unloading whereas the rule 
previously stated that Calculation Methodology 2 was to be used to 
calculate emissions from each well venting for liquids unloading event. 
This clarification is in line with

[[Page 47399]]

the equation in that the emissions from well venting for liquids 
unloading that have occurred in the year of data collection are to be 
summed and an annual value would result for all wells, as opposed to 
each well separately.
    We are proposing to amend Equation W-13 to include corrections and 
clarifications to the parameter definitions. First we are proposing to 
correct parameter Ea,n, EFwo, and Vf 
to state that they represent standard conditions and not actual 
conditions. Secondly, we are proposing a correction to the emission 
factor (EF) value in EFwo that was based on actual 
conditions and should have been in standard conditions. This proposed 
change would result in the emissions factor value adjustment 
EFwo = 2,454 to 3,114 standard cubic feet per workover. 
Next, we are proposing to revise the definition of Ea,n to 
Es,n to clarify that the annual natural gas emissions 
calculated are from a single gas well venting event and at standard 
conditions. Previously the rule stated that the Ea,n (now 
referred to as the Esn), represents emissions from gas well 
venting, which resulted in confusion as to whether this equation was to 
apply for gas well venting in previous years or to more than one gas 
well venting during the year of data collection. Finally, we are 
proposing to revise 40 CFR 98.233(h)(1). The rule states that the 
resulting emissions from Equation W-13 are to be converted into 
standard conditions. However, this should not be the case because 
Equation W-13 would already result in emissions in standard condition. 
As a result, we are proposing to include language in 40 CFR 
98.233(h)(1) that would reference paragraphs in subpart W that will 
convert the emissions from Equation W-13 into GHG volumetric and mass 
emissions.
    In Equation W-14 used for determining blowdown vent stacks 
emissions, we are proposing to clarify that the parameter Vv 
is the actual physical volume of the blowdown equipment and not the gas 
volume. It was always EPA's intent that the physical volume between 
isolation valves be considered against the 50 standard cubic feet 
threshold for blowdown vent stacks.\3\ EPA is also proposing to clarify 
the reporting requirements for blowdown vent stacks by stating that 
emissions are calculated per unique volume type and not equipment type. 
Equation W-14 in 40 CFR 98.233(i) determines emissions on a unique 
volume basis; therefore, emissions should be reported as such.
---------------------------------------------------------------------------

    \3\ Please see Response to Comment number EPA-HQ-OAR-2009-0923-
1018-27 in Mandatory Greenhouse Gas Reporting Rule Subpart W--
Petroleum and Natural Gas: EPA's Response to Public Comments, Volume 
8. This document can be found at http://www.epa.gov/climatechange/emissions/downloads10/Subpart-W_RTC_part2.pdf.
---------------------------------------------------------------------------

    In addition, we are proposing to make amendments to equations and 
parameters dependant on CH4 and CO2 composition 
by making clarifications to the parameter, GHGs used to convert whole 
gas, total hydrocarbon, or methane emissions into volumetric or mass 
CO2, and CH4 emissions in Equations W-1, W-2, W-
30, and W-31.
    In 40 CFR 98.233(j) we are proposing to clarify that the throughput 
threshold referenced in Calculation Methodologies 1-4 is based on an 
annual average daily throughput of oil, whereas the rule gave no 
clarification as to what basis the oil throughput was based on, 
resulting in many questions from affected owners and operators on how 
this throughput threshold was to be determined. We are also proposing 
to correct an erroneous citation in 40 CFR 98.234(j)(1)(vii) and 40 CFR 
98.233(j)(2), which referenced citations that do not exist. In Equation 
W-15, where volumetric GHG emissions are determined from onshore 
production storage tanks, we are proposing to revise the equation by 
including a multiplier so the resulting emissions would be in the 
correct units. In addition, we are proposing to amend the definition 
for the EFi and count parameters to clarify that these 
parameters must be used for both gas-liquid separators with throughput 
less than 10 barrels per day and wells with throughput less than 10 
barrels per day sending liquids straight to a tank without going 
through any separator. The definition to equation W-15 in the 2010 
final rule could have been misinterpreted to apply only to instances 
where there was a separator at the well. The proposed clarification 
makes the definitions to Equation W-15 consistent with the introduction 
to 40 CFR 98.233(j)(5).
    In Equation W-16, we are proposing to amend the definition for the 
parameter En by first correcting the citation that 
erroneously included 40 CFR 98.233(j)(3), which should not have been 
included because it references a methodology that is specific for wells 
that flow directly to storage tanks bypassing a wellhead separator. In 
addition, we are proposing to amend the definition for En by 
including a conversion factor that would result in the emissions being 
determined on a yearly basis as opposed to an hourly basis. In 
addition, we are proposing to delete the parameter Et in the 
equation as it is being accounted for in the revised equation and is no 
longer necessary.
    In 40 CFR 98.233(k) we are proposing the inclusion of minor 
revisions to 40 CFR 98.233(k)(2) and (k)(4) to clarify that emissions 
to be calculated are annual emissions. In addition, we are proposing to 
revise 40 CFR 98.233(k)(4)(i) by removing the reference to 40 CFR 
98.233(j)(1) as this reference was incorrectly directed to the onshore 
production storage tank calculations where owners and operators could 
use a software program to determine flashing emissions which are not 
covered under the transmission storage tanks calculations. Finally, we 
are also proposing to revise 40 CFR 98.233(k)(4)(ii) by clarifying that 
the flare stack calculations are to be used for emissions that are sent 
to a flare and not from a flare. The latter resulted in confusion from 
reporters as to what emissions they would be capturing by using the 
flare calculation methodologies.
    We are proposing to amend the provisions in 40 CFR 98.233(z) for 
determining combustion emissions from both the onshore petroleum and 
natural gas production and natural gas distribution industry segments. 
First, we are proposing to include an engineering equation to be used 
for determining CH4 emissions resulting from combustion of a 
fuel. The rule did not include a specific equation or methodology for 
determining the methane emissions from combustion of fuel, however, the 
provisions stated that both CH4 and CO2 emissions 
were to be calculated from the combustion of fuel. In addition, we are 
proposing to amend the equation used to calculate CO2 
emissions by including a combustion efficiency parameter.
    We are proposing to clarify that 40 CFR 98.233(z)(6), calculation 
of N2O emissions from stationary combustion, applies only to 
units combusting field gas or process vent gas. Units combusting other 
fuels listed in Table C-1 would estimate N2O (and 
CH4) emissions using the appropriate Tier 1 equations in 
subpart C. We have reorganized section 98.233(z)(6) to incorporate this 
proposed amendment. We are proposing to amend Equation W-40 to account 
for an incorrect exponent on the conversion factor from kilograms to 
metric tons. Without making this change to the rule, the emissions 
would have resulted in an incorrect calculation of emissions.
    We are also proposing to revise equation W-41 to insert missing 
variables a and b from the equation. Without including the missing 
variables, equation 41 would lack clarity and be unusable.

[[Page 47400]]

    Emission Factor Tables. We are proposing to revise the emission 
factors for high bleed, low bleed, and intermittent bleed pneumatic 
devices to correct for an error where the original emission factors 
were on a CH4 basis and should have been adjusted to account 
for the total hydrocarbon basis as noted in equation. These proposed 
revisions would apply to Table W-3 and Table W-4.
    Other Technical Corrections. EPA is proposing to clarify in 40 CFR 
98.236(c)(6)(ii)(B) that only the number of workovers with hydraulic 
fracturing that vent gas to the atmosphere or flare gas needs to be 
reported. The current rule language could suggest you must report on 
the total number of workovers per year, including those that don't 
involve hydraulic fracture and those that do not vent gas to the 
atmosphere.
    It came to EPA's attention that the density parameter in Equation 
W-36 was calculated incorrectly. EPA proposes correcting these 
parameters to 0.0520 kg/ft\3\ for CO2 and N2O, 
and 0.0190 kilograms per square foot (kg/ft\3\) for CH4 at 
68[deg] F and 14.7 pounds per square inch absolute (psia).

C. Subpart FF--Underground Coal Mines

    Proposed changes to Subpart A. We are proposing to amend Table A-3 
to subpart A of part 98. According to Table A-3 to subpart A of part 
98, all underground coal mines that are subject to quarterly or more 
frequent sampling by MSHA of ventilation systems (subpart FF) must 
report, regardless of size.
    This threshold was based on EPA's understanding that quarterly 
sampling by MSHA was only done at the largest, gassiest mines, defined 
as those emitting more than 100,000 actual cubic feet (acf) 
CH4 per day. For example, the proposal preamble states,

    ``We propose that all active underground coal mines for which 
CH4 from the ventilation system is sampled quarterly by 
MSHA (or on a more frequent basis), are required to report under 
this rule. MSHA conducts quarterly testing of CH4 
concentration and flow at mines emitting more than 100,000 cf 
CH4 per day. We selected this threshold because 
subjecting underground mine operators to a new emissions-based 
threshold is unnecessarily burdensome, as many of these mines are 
already subject to MSHA regulations. The MSHA threshold for 
reporting of 100,000 cf CH4 per day covers approximately 
94 percent of the CH4 emitted from underground coal mine 
ventilation systems and about 86 percent of total emissions from 
underground mining (including stationary fuel combustion emissions 
at mine sites, as shown in Table FF-1 of this preamble).''

    In the proposal preamble, we estimated that this threshold covers 
only about 128 of the estimated 612 active underground mines in the 
United States (74 FR 16553). Although it was not evident in reviewing 
the public comments received on the proposed subpart FF, since 
finalization we have learned that the threshold was based on an 
incorrect understanding that MSHA only samples quarterly at mines 
liberating 100,000 acf of CH4 or more per day.
    If the current regulatory threshold is retained, all mines would be 
required to report. This would add nearly 500 mines to the number 
previously expected to report, but these 500 mines would represent only 
another 14 percent of the total GHG emissions from underground coal 
mines. EPA is reviewing ways to address this and ensure that the 
threshold in the rule reflects EPA's longstanding intent to capture the 
gassiest mines that are responsible for the majority of emissions from 
underground coal mines in the United States.
    We are proposing to amend the language so that mines liberating 
36,500,000 acf of CH4 or more per year from their 
ventilation systems are subject to the rule. This capacity threshold 
(equivalent to an average of 100,000 acf of CH4 or more per 
day) may be more easily identifiable for the coal industry, is 
consistent with our original intent in terms of coverage, and removes 
reporting requirement for the approximately 500 mines.
    We considered but are not proposing, a threshold of 15,000 metric 
tons CO2e per year. This threshold would also be consistent 
with our original intent in terms of coverage and it would remove the 
reporting requirement for the approximately 500 mines. However, it 
would be less familiar to industry than the roughly equivalent 
threshold of 36,500,000 acf of CH4 or more per year.
    Equations FF-1 and FF-3. We are proposing the following technical 
amendments to Equations FF-1 and FF-3 in 40 CFR 98.323.
    We propose to amend 40 CFR 98.324(a) and 98.324(b) to specify that 
variables ``V,'' ``MCF,'' ``C,'' ``T,'' and ``P'' are not ``daily'' 
rates. We are also proposing to edit the units of ``V'' to cfm from 
scfm and to revise the units for ``C'' to read ``%'' to allow for the 
use of ``C'' on a dry basis.
    Sampling for pressure. We propose to amend FF-1 to allow facilities 
to use the annual average barometric pressure from the nearest NOAA 
weather service station as a default to measuring ventilation system 
pressure. According to MSHA, approved equipment to conduct pressure 
measurements is not readily available in the United States.
    Sampling for moisture content. We received numerous questions 
regarding the placement of timing of sampling for moisture content. We 
are proposing to add a paragraph (d) to 40 CFR 98.324 to specify that 
when flow and concentration are measured on different bases, moisture 
content is measured at the location of the flow meter at least weekly 
if using CEMS, and at the location and time of the grab sample, if 
using grab samples.
    Additionally, we received numerous inquiries about how reporters 
are to measure for moisture content, and asking whether measurements 
were really necessary because no moisture content measurement 
requirements are in 40 CFR 98.324. To clarify how and when reporters 
are to measure for moisture content, we are proposing to amend 40 CFR 
98.323 and 98.324 to include reference to calibration and documentation 
of procedures for moisture content monitors. These proposed amendments 
clarify that the moisture content is to be based on measurement values 
and not assumed moisture content values. In related amendments, we are 
proposing to amend 40 CFR 98.326(o) to clarify the reporting 
requirements for temperature, pressure, and moisture content 
measurements. Together, the proposed amendments to Equations FF-1 and 
FF-3 and 40 CFR 98.324 would clarify that moisture content need only be 
determined when the concentration and flow measurements are made on 
different basis (one wet and one dry) and that, if needed, the moisture 
content must be measured.
    MSHA data. We received numerous comments on the use of MSHA data to 
calculate emissions. MSHA samples volume and concentration of methane, 
but does not collect data on temperature, pressure, and moisture 
content, which are required inputs for the equations in this subpart. 
To allow facilities to use MSHA data, we propose to amend 40 CFR 
98.324(b)(2) to clarify that temperature and moisture content must be 
sampled at the same time and location as the MSHA samples, and that for 
pressure, facilities must use either a measured value or the average 
annual barometric pressure from the nearest NOAA weather service 
station.
    Monitoring equipment. We propose to amend 40 CFR 98.324(g) to 
include the use of infrared and flame ionization analyzers with the 
provision that they are calibrated annually using measurements made by 
gas chromatography methods. The infrared and flame ionization analyzers 
are

[[Page 47401]]

frequently used by the coal mining industry and they are often more 
familiar with their calibration and operation.
    We propose to amend 40 CFR 98.324(f) for consistency with the types 
of monitoring equipment required. We propose to replace references to 
``fuel flow meters'' with ``flow meters,'' because the gas that is 
measured may or may not be used as a fuel. We also propose to delete 
references to ``heating value monitors,'' and ``sour gas flow meters'' 
because these monitors and meters are not required.

D. Subpart II--Industrial Wastewater Treatment

    We are proposing clarifying amendments and technical corrections to 
subpart II to address questions EPA has received about the rule's 
requirements, as well as to clarify terminology.
    We are proposing to amend 40 CFR 98.352(d) to replace the term 
``landfill gas'' with ``biogas'' to correct a typographical error.
    We are proposing to amend the definitions of the terms for 
``Tm'' and ``Pm'' in Equation II-4 to refer to 
``average temperature'' and ``average pressure'' to clarify how 
reporters should use the multiple temperature and pressure measurements 
that they may make during a measurement period. We are also proposing 
to amend these definitions to clarify how the calculation should be 
adjusted if the flow rate meter automatically corrects for temperature 
and pressure.
    We are proposing to amend 40 CFR 98.353(c)(2)(ii), 40 CFR 
98.353(c)(2)(iii)(A) and (B), and 40 CFR 98.354(c) and (d) to replace 
``once each calendar week, with at least three days between 
measurements'' with ``at least once each calendar week; if only one 
measurement is made each calendar week, there must be at least three 
days between measurements,'' to clarify what is meant by weekly 
sampling.
    We are proposing to amend Equation II-6 of 40 CFR 98.353 to correct 
an error in the placement of brackets and parentheses. This amendment 
will eliminate the possibility that the equation will return incorrect 
quantities of methane emissions. We are also proposing to amend the 
units in the definition of CH4En under Equation 
II-6 to clarify that the annual quantity should be reported in ``metric 
tons'' not ``metric tons/yr.''
    We are proposing to amend 40 CFR 98.353(c) to reorder the text to 
clarify that continuous gas flow monitoring is required for each 
anaerobic sludge digester, anaerobic reactor, or anaerobic lagoon from 
which some biogas is recovered; and to clarify that the continuous gas 
flow measurements must be used to determine cumulative gas production 
each week. We are also proposing to amend 40 CFR 98.353(c)(1) to 
replace the term ``content'' with the term ``quantity'' to clarify that 
fully integrated systems report CH4 quantity which accounts 
for both CH4 concentration and biogas flow.
    We are proposing to amend 40 CFR 98.354(f) by dividing it into 
subparagraphs and by deleting an incorrect cross reference, to clarify 
the monitoring requirements for anaerobic sludge digester, anaerobic 
reactor, or anaerobic lagoon from which some biogas is recovered.
    We are proposing to amend 40 CFR 98.356(a) by replacing the term 
''explain'' with ``indicate'' to provide guidance to reporters about 
the information they should include in the description or diagram of 
their wastewater treatment system. We are also proposing to replace the 
term ``all anaerobic lagoons'' with ``each anaerobic lagoon'' to 
clarify that reporters should provide the average depth of each lagoon, 
not the average of all lagoons.
    We are proposing to amend 40 CFR 98.356(b)(3) and (4) to clarify 
that the values for ``Bo'' and ``MCF,'' that are used as inputs to 
Equation II-1 or II-2, are to be taken from Table II-1. We are also 
proposing to amend 40 CFR 98.356(d)(2) by replacing the text 
``Cumulative volumetric biogas flow for each week'' with ``Total weekly 
volumetric biogas flow for each week (up to 52 weeks/year)'' to clarify 
that reporters should provide the total gas recovered for the week, for 
up to 52 weeks per year.
    We are proposing to amend subpart II (Industrial Wastewater 
Treatment) (40 CFR 98.350 to 40 CFR 98.358) in multiple places, 
replacing the term ``anaerobic digester'' with ``anaerobic sludge 
digester'' to clarify the test refers to the anaerobic process defined 
in 40 CFR 98.350(b)(2); and to replace the term ``gas'' with ``biogas'' 
to clarify the gas referred to is the biogas defined in 40 CFR 98.358.

E. Subpart OO--Suppliers of Industrial Greenhouse Gases

    We are proposing to amend subpart OO to require that the data 
currently reported under 40 CFR 98.416(a)(8) and (9) be kept as a 
record rather than reported. We are also proposing to make a 
corresponding revision to 40 CFR 98.416(a)(10).
    Section 98.416(a)(8) requires that fluorinated GHG and nitrous 
oxide production facilities report the total mass in metric tons of 
each reactant fed into the F-GHG or nitrous oxide production process, 
by process; and section 98.416(a)(9) requires that fluorinated GHG and 
nitrous oxide production facilities report the total mass in metric 
tons of the reactants, by-products, and other wastes permanently 
removed from the F-GHG or nitrous oxide production process, by process. 
Although these data elements do not, in themselves, represent additions 
to or subtractions from the U.S. supply of industrial GHGs, we required 
reporting of these data elements in the October 30, 2009, Mandatory GHG 
Reporting Rule to facilitate verification of production levels through 
a material balance. (For more discussion of that decision, see page 26 
of the Mandatory Greenhouse Gas Reporting Rule: EPA's Response to 
Public Comments, Volume No. 40, Subpart OO--Suppliers of Industrial 
Greenhouse Gases.)
    We are now proposing to require recordkeeping, rather than 
reporting, of these data elements. After additional consideration, we 
have concluded that these data elements, by themselves, have somewhat 
limited usefulness for verifying production levels because the 
relationship between the masses of the reactants fed into the process, 
the mass of the nitrous oxide or fluorinated GHG product, and the mass 
of the reactants, by-products, and other wastes permanently removed 
from the process can vary. For example, if catalysts are added to the 
process and subsequently removed from it, the sum of the masses of the 
product and the materials removed from the process may exceed the sum 
of the masses of the reactants fed into the process. On the other hand, 
if by-products or other materials are emitted from the process, e.g., 
through fugitive emissions, the sum of the masses of the reactants may 
exceed the sum of the masses of the product and the materials removed 
from the process. Finally, the accuracies and precisions of the various 
instruments used to measure the masses of the reactants fed into the 
process, the mass of the nitrous oxide or fluorinated GHG produced, and 
the masses of the materials permanently removed from the process may 
all vary, further complicating comparisons among these quantities. 
Retention of these data as records would permit on-site verification of 
production as part of the audit process, which would have the benefit 
of permitting consideration of other production process information 
(e.g., the use of catalysts) in making comparisons among the inputs and 
outputs of the production process. We

[[Page 47402]]

estimate that approximately 20 facilities produce fluorinated GHGs or 
nitrous oxide in the U.S., making on-site verification a practicable 
option for subpart OO.
    We are also proposing to revise Sec.  98.416(a)(10) by removing the 
introductory qualifier. In its entirety, the provision currently reads, 
``For transformation processes that do not produce an F-GHG or nitrous 
oxide, mass in metric tons of any fluorinated GHG or nitrous oxide fed 
into the transformation process, by process.'' The phrase ``for 
transformation processes that do not produce an F-GHG or nitrous 
oxide'' was intended to prevent double-reporting between this provision 
and Sec.  98.416(a)(8), which requires reporting of the mass of each 
reactant fed into the fluorinated GHG or nitrous oxide production 
process. (In the case where one fluorinated GHG was transformed into 
another, the first fluorinated GHG would be one of the reactants fed 
into the process and would therefore be reported under (a)(8).) With 
the proposed removal of Sec.  98.416 (a)(8), the introductory qualifier 
in Sec.  98.416(a)(10) must be removed to ensure that the quantities of 
fluorinated GHGs fed into all transformation processes, including 
transformation processes that produce other fluorinated GHGs, will be 
reported under subpart OO.\4\
---------------------------------------------------------------------------

    \4\ Note that if a fluorinated GHG is produced and transformed 
at the same facility, neither its production nor its transformation 
are required to be reported under subpart OO.
---------------------------------------------------------------------------

F. Subpart RR--Geologic Sequestration of Carbon Dioxide

    We are proposing clarifying amendments and technical corrections to 
subpart RR to correct known errors.
    Accounting for CO2 Entrained in Produced Water. We are 
proposing to clarify 40 CFR 98.443(d) to ensure that CO2 
entrained in produced water that is not processed through a gas-liquid 
separator is accounted for in the mass balance equation. We intended 
that CO2 content in all produced liquids would be 
determined,\5\ and assumed that all produced liquids would be processed 
through a gas-liquid separator. The text in 40 CFR 98.443(d), and the 
associated equations (Equations RR-7, RR-8, and RR-9) are based on 
measurements made at a separator to calculate the amount of 
CO2 in produced fluids. However, EPA has recognized that in 
some situations, including water removed for pressure relief or 
reservoir maintenance, fluids may be removed from the subsurface 
without being processed through a separator. The current text and 
equations would not account for CO2 in water that is 
withdrawn from the subsurface and reinjected or disposed without going 
through a separator.
---------------------------------------------------------------------------

    \5\ See Section II.B.4 of preamble to the final Subpart RR rule 
(75 FR 75065, December 1, 2010).
---------------------------------------------------------------------------

    To address this issue, we propose adding a new sentence to 40 CFR 
98.443(d) to specifically account for any CO2 in fluids that 
are produced and not processed through a separator. We also propose 
adding a new sentence to 40 CFR 98.443(d)(3) to clarify that the 
reporter must include additional information regarding the measurement 
methods used to determine the concentration of CO2 in 
fluids, and a discussion of how the amount of produced CO2 
would be determined, in the monitoring, reporting and verification 
(MRV) plan. In the MRV plan, the reporter would describe the 
disposition of the produced water (reinjected into another zone, 
reused, or otherwise disposed) and provide justification for 
determining whether the CO2 entrained in the water is 
sequestered. The MRV plan would also describe considerations the 
reporter intends to use to calculate CO2 from produced water 
for the mass balance equation.
    CO2 Emissions from Equipment Leaks and Vented Emissions of CO2. We 
are proposing to revise the term ``CO2 equipment leakage and 
vented CO2 emissions'' throughout subpart RR with the term 
``CO2 emissions from equipment leaks and vented emissions of 
CO2.'' This change is proposed to ensure consistency with 
the terminology that is used in 40 CFR part 98 subpart W and to more 
accurately describe the equipment between flow meters and wellheads for 
which monitoring requirements are specified in subpart RR. 
Specifically, we are proposing the following changes:
     At 40 CFR 98.442(e) and 98.442(f), revise the term ``Mass 
of CO2 equipment leakage and vented CO2 
emissions'' to read ``Mass of CO2 emissions from equipment 
leaks and vented emissions of CO2.''
     In Equations RR-11 and RR-12 at 40 CFR 98.443, revise the 
term ``Total annual CO2 mass emitted (metric tons) as 
equipment leakage or vented emissions'' to read ``Total annual 
CO2 mass emitted (metric tons) from equipment leaks and 
vented emissions of CO2.''
     At 40 CFR 98.444(d), revise the heading ``CO2 
equipment leakage and vented CO2 emissions'' to read 
``CO2 emissions from equipment leaks and vented emissions of 
CO2.''
     At 40 CFR 98.445(e), revise the term ``CO2 
equipment leakage or vented CO2 emissions to read 
``CO2 emissions from equipment leaks and vented emissions of 
CO2.''
     At the introductory text of 40 CFR 98.446(f)(3), revise 
the term ``CO2 equipment leakage and vented CO2 
emissions'' to read ``CO2 emissions from equipment leaks and 
vented emissions of CO2.''
     At 40 CFR 98.446(f)(3)(i) and 98.446(f)(3)(ii), revise the 
term ``mass of CO2 emitted (in metric tons) annually as 
equipment leakage or vented emissions'' to read ``mass of 
CO2 emitted (in metric tons) annually from equipment leaks 
and vented emissions of CO2.''
     At 40 CFR 98.447(a)(5) and 98.447(a)(6), revise the term 
``CO2 emitted as equipment leakage or vented emissions'' to 
read ``CO2 emitted from equipment leaks and vented emissions 
of CO2.''
     At 40 CFR 98.448(a)(5), revise the term ``considerations 
for calculating equipment leakage and vented emissions'' to read 
``considerations for calculating CO2 emissions from 
equipment leaks and vented emissions of CO2.''
    Other Technical Corrections. We are proposing to amend a cross 
reference in the introductory language of 40 CFR 98.446(a)(2) and 40 
CFR 98.446(a)(3). The incorrect references refer the reader to 40 CFR 
98.446(a)(5), but should refer the reader 40 CFR 98.446(a)(4). We are 
also proposing to amend a cross reference at 40 CFR 98.446(f)(1)(vii). 
The incorrect reference refers the reader to 40 CFR 98.446(f)(1)(i), 
but should refer the reader to 40 CFR 98.446(f)(1)(ii).
    We are proposing to revise the data reporting element at 40 CFR 
98.446(e) and the introductory text at 40 CFR 98.446(f). As currently 
written, it is ambiguous when reporters would report total amount 
sequestered. We are proposing that the revised data reporting element 
at 40 98.446(e) read as follows: ``Report the date that you began 
collecting data for calculating total amount sequestered according to 
Sec.  98.448(a)(7) of this subpart''. We are proposing that the revised 
introductory text at 40 CFR 98.446(f) read as follows: ``Report the 
following. If the date specified in paragraph (e) of this section is 
during the reporting year for this annual report, report the following 
starting on the date specified in paragraph (e) of this section.''
    We are proposing to revise the heading of 40 CFR 98.448(e) to 
correct a typographical error. The text of 40 CFR 98.448(e) refers to 
requirements for revised MRV plans, but the heading is incorrectly 
labeled as ``Final MRV plan.'' We propose to revise the heading to read 
``Revised MRV plan.''

[[Page 47403]]

    We are proposing to revise the definition of ``CO2 
received'' at 40 CFR 98.449 to correct a typographical error by adding 
the word ``means'' after the CO2 received defined term. The 
definition would read ``CO2 received means the 
CO2 stream that you receive to be injected for the first 
time into a well on your facility that is covered by this subpart. 
CO2 received includes, but is not limited to, a 
CO2 stream from a production process unit inside your 
facility and a CO2 stream that was injected into a well on 
another facility, removed from a discontinued enhanced oil or natural 
gas or other production well, and transferred to your facility.''

G. Subpart TT--Industrial Waste Landfills

    Numerous clarifying amendments and technical corrections are 
proposed to subpart TT to address questions EPA has received about the 
rule's requirements and to correct known errors. Technical amendments 
to the rule are also proposed to address some additional questions. 
These more substantive technical amendments are discussed first, and 
then the clarifying amendments are presented.
    Determining Waste-specific DOC values for Closed Landfills. We are 
proposing to amend 40 CFR 98.464 by adding a new paragraph (c) to 
provide methodologies for closed landfills or active landfills that 
have stopped accepting certain types of wastes to determine the 
volatile solids concentration (for exemption purposes under 40 CFR 
98.460(c)(2)(xii)) or to determine the waste-specific DOC values for 
historically disposed waste streams. The proposed provisions would 
allow landfills to identify waste streams similar to those that had 
been historically placed in the landfill, measure the volatile solids 
concentration of these ``similar'' waste streams, and use those 
measured values to assess the applicability of the exemption under 40 
CFR 98.460(c)(2)(xii) or to determine the average DOC value for the 
historical waste streams. The proposed provisions also allow use of 
process knowledge to determine the volatile solids concentration and, 
if needed, to calculate the corresponding DOC value if a similar waste 
stream cannot be identified.
    This provision is being proposed to allow industrial waste landfill 
owners and operators a means by which to develop volatile solids 
concentration and site-specific DOC values for historically disposed 
waste streams. The site-specific DOC values will in turn improve the 
accuracy of the modeled methane generation. The July 12, 2010, final 
rule had no provisions by which waste streams that were not disposed of 
in the landfill during the first reporting year could be assessed. 
These waste streams would be required to use the default DOC values, 
which have a higher degree of uncertainty. Facilities may still elect 
to use the default DOC values, but proposed amendments provide 
methodologies for developing site-specific DOC values for these 
``historically-disposed'' waste streams.
    We are also proposing to amend 40 CFR 98.467 to clarify that 
records must be retained for the volatile solids concentration 
determinations, including determinations using process knowledge.
    Equations for Determining Volatile Solids and DOC Values. We are 
proposing to delete Equation TT-7 and amend Equation TT-8 to 40 CFR 
98.464 to correct inadvertent errors in these equations. These 
equations as presented in the July 12, 2010, final rule were incorrect 
because the volatile solids concentration was expected to have units of 
mass of volatile solids per mass of (wet) waste. However, per Standard 
Method 2540G ``Total, Fixed, and Volatile Solids in Solid and Semisolid 
Samples,'' the volatile solids concentration is determined on a dry 
basis (milligram (mg) volatile solids per mg dried solids). As such, 
Standard Method 2540G provides the volatile solids concentration in the 
appropriate units needed for 40 CFR 98.464(b)(3), and Equation TT-7 in 
the final rule can be deleted. Additionally, we propose to amend 40 CFR 
98.464(b)(4) to correct the errors in Equation TT-8 (which is proposed 
to be renumbered as Equation TT-7) and to clarify the units of the 
variables used in the equation.
    We are revising the variable ``F'' in Equation TT-1 and new 
Equation TT-7 (which was Equation TT-8) to correct the measured 
CH4 concentration for zero percent oxygen. We are proposing 
to change ``Fx'' to be ``F'' in Equation TT-1 because this 
parameter should be a fixed value for a given reporting year and 
revising the definition of ``F'' to be ``Fraction by volume of 
CH4 in landfill gas (fraction, dry basis, corrected to 0% 
oxygen). If you have a gas collection system, use the annual average 
CH4 concentration from measurement data for the current 
reporting year; otherwise, use the default value of 0.5'' to clarify 
that, if a measured value of CH4 concentration is used it 
should be based on measurements made during the reporting year and the 
volume fraction should be adjusted to 0 percent oxygen for use in 
Equation TT-1.
    In addition, we are proposing to add a new paragraph (g) in 40 CFR 
98.464 and a new Equation TT-8 to provide guidance on how to correct 
the measured CH4 concentration for zero percent oxygen in 
order to arrive at an appropriate value for F in the case of air 
infiltration into the landfill gas at the monitoring location.
    Provisions for Actively Aerated Landfills and Other Amendments To 
Conform with Amendments to subpart HH. Similar to amendments that were 
made to subpart HH (Municipal Solid Waste Landfills), we propose to 
amend the definition of the methane correction factor (MCF) to allow 
landfills with active aeration units to use an MCF value other than the 
default value of 1. For landfills with active aeration units, a site-
specific MCF can be developed based on the amount of aeration and the 
fraction of the landfill that is actively aerated. Owners and operators 
of landfills with active aeration can use the default MCF factor of 1 
or they may elect to develop a site-specific MCF value. The owner or 
operator of the industrial waste landfill must document the basis for 
the alternative MCF value; in no cases can an MCF value less than 0.5 
be used. These amendments are being proposed because the default MCF 
value of 1 is expected to overestimate the modeled methane generation 
at a facility that actively aerates the waste in the landfill. 
Additionally, we propose to add 40 CFR 98.466(d)(4) to require 
reporting of the MCF value and the basis for using an MCF value other 
than the default value of 1.
    We are proposing to define the term ``construction and demolition 
waste landfills'' as defined in subpart HH and use that term rather 
than ``dedicated construction and demolition waste landfills.''
    We are also proposing to revise the footnote to Table TT-1 to 
subpart TT of part 98 to clarify that leachate recirculation rates can 
be determined from company records or engineering estimates and that 
the owner or operator of a landfill that uses leachate recirculation 
may elect to use the k value for the wet climate rather than 
calculating the leachate recirculation rate. These amendments provide 
improved consistency between the reporting requirements for municipal 
and industrial waste landfills.
    Other Technical Corrections. We are proposing other technical 
corrections for subpart TT to correct typographical errors, to correct 
equations, and to provide minor clarifications. These proposed 
corrections are summarized below:

[[Page 47404]]

     In 40 CFR 98.460(c)(2)(i), replacing ``Coal combustion 
residue (e.g., fly ash)'' with ``Coal combustion or incinerator ash 
(e.g., fly ash)'' to better describe our intent to classify all 
combustion ash products as inert.
     In 40 CFR 98.463(a)(1):

--Revising the definition of GCH4 to delete the word 
``rate'' because the units of the modeled methane generation is metric 
tons.
--Revising the definition of DOCx from ``degradable organic 
carbon for year X * * *'' to be ``degradable organic carbon for waste 
disposed in year X * * *'' for clarity.

     In 40 CFR 98.463(a)(2):

--Revising ``January 1, 1980'' to be ``January 1, 1960'' in both places 
to correct an inadvertent error.
--Replacing the term ``first emissions monitoring year'' with ``first 
emissions reporting year'' to improve consistency with the terminology 
used in other sections of subpart TT.

     In 40 CFR 98.463(a)(2)(ii)(C):

--Deleting the phrase ``fixed average annual bulk waste disposal 
quantity for each year for which historic disposal quantity and'' in 
the paragraph text and adding to the definition of WX ``This 
annual bulk waste disposal quantity applies for all years from `YrOpen' 
to `YrData' inclusive'' to clarify that the value calculated by 
Equation TT-4 applies for all years from ``YrOpen'' to ``YrData'' 
inclusive.

--Revising the definition of LFC and YrData to allow closed landfills 
that have some measurement data to appropriately calculate 
WX only for years for which the closed landfill does not 
have waste disposal data available from company records or from 
Equation TT-3.

     In 40 CFR 98.464(b), replacing ``For each waste stream for 
which you choose to determine * * *'' with ``For each waste stream 
received during the reporting year for which you choose to determine * 
* *'' for clarity given the addition of 40 CFR 98.464(c).
     In 40 CFR 98.464(b)(1), adding the parenthetical ``(as 
received at the landfill)'' to clarify that the representative sample 
of each waste stream was to be determined ``as received at that 
landfill'' (as opposed to sampling waste in ``closed'' sections of the 
landfill) and for clarity given the addition of 40 CFR 98.464(c).
     In 40 CFR 98.466(b), replacing ``Report the following 
waste characterization information:'' with ``Report the following waste 
characterization and modeling information:'' to better describe the 
reporting elements included in this paragraph.
     Moving paragraphs 40 CFR 98.466(d)(3) and (4) to 
98.466(b)(3) and (4) because these reporting elements are based on 
reporting year practices and do not need to be separately reported for 
each year or used in the summation for Equation TT-1. Also, to clarify 
that the fraction of CH4 in the landfill gas, F, should be 
based on CH4 concentration corrected to 0% oxygen.
     In 40 CFR 98.466(b)(2), adding ``* * * for which Equation 
TT-1 of this subpart is used to calculate modeled CH4 
generation'' to clarify that only descriptions of waste streams 
disposed of in the landfill and used in Equation TT-1 must be reported 
(as opposed to all wastes managed on-site regardless of whether the 
waste in managed in the landfill).
     In 40 CFR 98.466(c)(3)(ii), replacing ``The year, the 
waste disposal quantity and production quantity for each year Equation 
TT-2 applies'' with ``The year, the waste disposal quantity and 
production quantity for each year used in Equation TT-2 of this subpart 
to calculate the average waste disposal factor (WDF)'' to clarify that 
these data are to be reported for the years used to calculate WDF, not 
the years for which WDF was subsequently used to calculate waste 
quantities.
     In 40 CFR 98.466(d), adding the phase ``and each year 
thereafter up'' so that the paragraph reads ``For each year of 
landfilling starting with the ``Start Year'' (S) and each year 
thereafter up to the current reporting year, report the following 
information:'' to clarify that the reporting elements must be reported 
separately for each year.
     Adding a new paragraph 40 CFR 98.466(d)(1) to read ``The 
calendar year for which following data elements apply'' to ensure the 
calendar year is also reported. Renumber existing paragraphs 
98.466(d)(1) and (2) to (d)(2) and (3) and add the phrase ``for the 
specified year'' to ensure the data elements are reported with 
specified year in the new paragraph 98.466(d)(1).
     In 40 CFR 98.466(f), deleting the word ``rate'' to conform 
with revised definition of term and replace it with 
``(GCH4)'' to clarify this is the equation term to be 
reported.
     In 40 CFR 98.466(f), adding ``(MG)'' after ``methane 
generation'' to improve clarity and replace ``Equation TT-5'' with 
``Equation TT-6'' to correct an improper equation cross-reference.
     In 40 CFR 98.468, adding the definition of ``design 
capacity'' to clarify what is meant by this term as it is used in 40 
CFR 98.460. The definition is similar to 40 CFR 60.751 (Standards of 
Performance for Municipal Solid Waste Landfills).
     In Table TT-1, amending the default value of construction 
and demolition waste from 0.04 to 0.08 to correct an inadvertent error.
     In Table TT-1, revising the description of the waste type 
``Inert Waste'' to read ``Inert Waste [i.e., wastes listed in 40 CFR 
98.460(c)(2)]'' to correct an incorrect cross-reference.

III. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive 
Order 13563: Improving Regulation and Regulatory Review

    This action is not a ``significant regulatory action'' under the 
terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is 
therefore not subject to review under Executive Orders 12866 and 13563 
(76 FR 3821, January 21, 2011).

B. Paperwork Reduction Act

    This action does not impose any new information collection burden. 
These proposed amendments do not make any substantive changes to the 
reporting requirements in any of the subparts for which amendments are 
being proposed. In many cases, the proposed amendments to the reporting 
requirements could potentially reduce the reporting burden by making 
the reporting requirements conform more closely to current industry 
practices. However, the OMB has previously approved the information 
collection requirements for subparts A and OO contained in the 
regulations promulgated on October 30, 2009, subpart W promulgated on 
November 30, 2010, subpart DD promulgated on December 1, 2010, subparts 
FF and TT promulgated on July 12, 2010, and subpart RR promulgated on 
December 1, 2010 under 40 CFR part 98 under the provisions of the 
Paperwork Reduction Act, 44 U.S.C. 3501 et seq., and has assigned OMB 
control numbers 2060-0629; 2060-0650; and 2060-0647; and 2060-0649 
respectively. The OMB control numbers for EPA's regulations in 40 CFR 
are listed in 40 CFR part 9.
    Further information on EPA's assessment on the impact on burden can 
be found in the Technical Corrections and Amendments Cost Memo in 
docket number EPA-HQ-OAR-2011-0147.

C. Regulatory Flexibility Act (RFA)

    The RFA generally requires an agency to prepare a regulatory 
flexibility analysis of any rule subject to notice

[[Page 47405]]

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 this proposed rule on 
small entities, small entity is defined as: (1) A small business as 
defined by the Small Business Administration's 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 these proposed rule 
amendments on small entities, I certify that this action will not have 
a significant economic impact on a substantial number of small 
entities. The proposed rule amendments will not impose any new 
requirement on small entities that are not currently required by the 
regulation of subparts A and OO promulgated on October 30, 2009; 
subparts FF, II, and TT promulgated on July 12, 2010; subpart W 
promulgated on November 30, 2010, or subparts DD or RR, both 
promulgated on December 1, 2010.
    EPA took several steps to reduce the impact of 40 CFR part 98 on 
small entities when developing the final GHG reporting rules in 2009 
and 2010. For example, EPA determined appropriate thresholds that 
reduced the number of small businesses reporting. In addition, EPA 
conducted several meetings with industry associations to discuss 
regulatory options and the corresponding burden on industry, such as 
recordkeeping and reporting. Finally, EPA continues to conduct 
significant outreach on the GHG reporting program and maintains an 
``open door'' policy for stakeholders to help inform EPA's 
understanding of key issues for the industries.
    We continue to be interested in the potential impacts of the 
proposed rule amendments on small entities and welcome comments on 
issues related to such impacts.

D. Unfunded Mandates Reform Act (UMRA)

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 
U.S.C. 1531-1538, requires Federal agencies, unless otherwise 
prohibited by law, to assess the effects of their regulatory actions on 
State, local, and Tribal governments and the private sector. Federal 
agencies must also develop a plan to provide notice to small 
governments that might be significantly or uniquely affected by any 
regulatory requirements. The plan must enable officials of affected 
small governments to have meaningful and timely input in the 
development of EPA regulatory proposals with significant Federal 
intergovernmental mandates and must inform, educate, and advise small 
governments on compliance with the regulatory requirements.
    The proposed rule amendments do 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. Thus, the proposed rule amendments are not subject to the 
requirements of section 202 and 205 of the 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. The proposed amendments will not impose any new 
requirements that are not currently required for 40 CFR part 98, and 
the rule amendments would not unfairly apply to small governments. 
Therefore, this action is not subject to the requirements of section 
203 of the UMRA.

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.
    These amendments apply directly to facilities that supply certain 
products that would result in GHGs when released, combusted or oxidized 
and facilities that directly emit greenhouses gases. They do not apply 
to governmental entities unless the government entity owns a facility 
that directly emits GHGs above threshold levels (such as a landfill), 
so relatively few government facilities would be affected. This 
regulation also does not limit the power of States or localities to 
collect GHG data and/or regulate GHG emissions. Thus, Executive Order 
13132 does not apply to this action.
    Although section 6 of Executive Order 13132 does not apply to this 
action, EPA did consult with State and local officials or 
representatives of State and local governments in developing subparts A 
and OO promulgated on October 30, 2009; subparts FF, II, and TT 
promulgated on July 12, 2010; subpart W promulgated on November 30, 
2010, and subparts DD and RR, both promulgated on December 1, 2010. A 
summary of EPA's consultations with State and local governments is 
provided in Section VIII.E of the preamble to the 2009 final rule.
    In the spirit of Executive Order 13132, and consistent with EPA 
policy to promote communications between EPA and State and local 
governments, EPA specifically solicits comment on this proposed action 
from State and local officials.

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

    This action does not have tribal implications, as specified in 
Executive Order 13175 (65 FR 67249, November 9, 2000). The proposed 
rule amendments would not result in any changes to the current 
requirements of 40 CFR part 98. Thus, Executive Order 13175 does not 
apply to this action.
    Although Executive Order 13175 does not apply to this action, EPA 
sought opportunities to provide information to Tribal governments and 
representatives during the development of the rules for subparts A and 
OO promulgated on October 30, 2009; subparts FF, II, and TT promulgated 
on July 12, 2010; subpart W promulgated on November 30, 2010, and 
subparts and DD and RR, both promulgated on December 1, 2010. A summary 
of the EPA's consultations with Tribal officials is provided in 
Sections VIII.D and VIII.F of the preamble to the 2009 final rule and 
in Section IV.F of the final rule for subpart W.

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

    EPA interprets Executive Order 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 Executive Order has the potential to influence the regulation. This 
action is not subject to Executive Order 13045 because it does not 
establish an environmental standard intended to mitigate health or 
safety risks.

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

    This action is not subject to Executive Order 13211 (66 FR 28355, 
May 22, 2001), because it is not a significant

[[Page 47406]]

regulatory action under Executive Order 12866.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (NTTAA), Public Law No. 104-113 (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 proposed rulemaking does not involve technical standards. 
Therefore, EPA is not considering the use of any voluntary consensus 
standards.

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

    Executive Order 12898 (59 FR 7629, February 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 because it is a rule addressing information collection and 
reporting procedures.

List of Subjects in 40 CFR Part 98

    Environmental protection, Administrative practice and procedure, 
Greenhouse gases, Suppliers, Reporting and recordkeeping requirements.

    Dated: July 19, 2011.
Lisa P. Jackson,
Administrator.
    For the reasons stated in the preamble, part 98 of title 40, 
chapter I, of the Code of Federal Regulations is proposed to be amended 
as follows:

PART 98--[AMENDED]

    1. The authority citation for part 98 continues to read as follows:

    Authority:  42 U.S.C. 7401-7671q.

    2. Section 98.2 is amended by:
    a. Revising paragraph (d).
    b. Revising paragraph (e).
    c. Revising paragraph (f) introductory text.
    d. Revising paragraph (h).
    e. Revising paragraph (i)(3).

Subpart A--[Amended]

Sec.  98.2  Who must report?

* * * * *
    (d) To calculate GHG quantities for comparison to the 25,000 metric 
ton CO2 per year threshold for importers and exporters of 
coal-to-liquid products under paragraph (a)(4) of this section, 
calculate the mass in metric tons per year of CO2 that would 
result from the complete combustion or oxidation of the quantity of 
coal-to-liquid products that are imported during the reporting year 
and, that are exported during the reporting year. Compare the imported 
quantities and the exported quantities separately to the 25,000 metric 
ton CO2 per year threshold. Calculate the quantities using 
the methodology specified in subpart LL of this part.
    (e) To calculate GHG quantities for comparison to the 25,000 metric 
ton CO2e per year threshold for importers and exporters of 
petroleum products under paragraph (a)(4) of this section, calculate 
the mass in metric tons per year of CO2 that would result 
from the complete combustion or oxidation of the combined volume of 
petroleum products and natural gas liquids that are imported during the 
reporting year and that are exported during the reporting year. Compare 
the imported quantities and the exported quantities separately to the 
25,000 metric ton CO2 per year threshold. Calculate the 
quantities using the methodology specified in subpart MM of this part.
    (f) To calculate GHG quantities for comparison to the 25,000 metric 
ton CO2e per year threshold under paragraph (a)(4) of this 
section for importers and exporters of industrial greenhouse gases and 
for importers and exporters of CO2, the owner or operator 
shall calculate the mass in metric tons per year of CO2e 
imports and exports as described in paragraphs (f)(1) through (f)(3) of 
this section. Compare the imported quantities and the exported 
quantities separately to the 25,000 metric ton CO2 per year 
threshold.
* * * * *
    (h) An owner or operator of a facility or supplier that does not 
meet the applicability requirements of paragraph (a) of this section is 
not subject to this rule. Such owner or operator would become subject 
to the rule and reporting requirements, if a facility or supplier 
exceeds the applicability requirements of paragraph (a) of this section 
at a later time pursuant to Sec.  98.3(b)(3). Thus, the owner or 
operator should reevaluate the applicability to this part (including 
the revising of any relevant emissions calculations or other 
calculations) whenever there is any change that could cause a facility 
or supplier to meet the applicability requirements of paragraph (a) of 
this section. Such changes include but are not limited to process 
modifications, increases in operating hours, increases in production, 
changes in fuel or raw material use, addition of equipment, and 
facility expansion.
    (i) * * *
    (3) If the operations of a facility or supplier are changed such 
that all applicable GHG-emitting processes and operations listed in 
paragraphs (a)(1) through (a)(4) of this section cease to operate, then 
the owner or operator is exempt from reporting in the years following 
the year in which cessation of such operations occurs, provided that 
the owner or operator submits a notification to the Administrator that 
announces the cessation of reporting and certifies to the closure of 
all GHG-emitting processes and operations no later than March 31 of the 
year following such changes. This paragraph (i)(3) does not apply to 
seasonal or other temporary cessation of operations. This paragraph 
(i)(3) does not apply to facilities with municipal solid waste 
landfills or industrial waste landfills, or to underground coal mines. 
The owner or operator must resume reporting for any future calendar 
year during which any of the GHG-emitting processes or operations 
resume operation.
* * * * *
    3. Section 98.3 is amended by:
    a. Revising paragraph (b) introductory text.
    b. Revising paragraph (b)(1).
    c. Adding paragraph (b)(4).
    d. Revising paragraph (c)(5)(ii).
    e. Revising paragraph (c)(7).
    f. Revising paragraph (c)(10).
    g. Revising paragraph (c)(11).
    h. Revising the second sentence of paragraph (g) introductory text.

[[Page 47407]]

Sec.  98.3  What are the general monitoring, reporting, recordkeeping 
and verification requirements of this part?

* * * * *
    (b) Schedule. The annual GHG report for reporting year 2010 must be 
submitted no later than September 30, 2011. The annual report for 
reporting years 2011 and beyond must be submitted no later than March 
31 of each calendar year for GHG emissions in the previous calendar 
year, except as provided in paragraph (b)(1) of this section.
    (1) For reporting year 2011, GHG information required by the 
subparts listed in paragraphs (b)(1)(i) through (b)(1)(xii) of this 
section must be submitted no later than September 28, 2012. This 
reporting date applies only to the data reporting requirements 
identified in the listed subparts and does not affect data reporting 
requirements of other subparts that apply to a facility or supplier.
    (i) Electronics Manufacturing (subpart I).
    (ii) Fluorinated Gas Production (subpart L).
    (iii) Magnesium Production (subpart T).
    (iv) Petroleum and Natural Gas Systems (subpart W).
    (v) Use of Electric Transmission and Distribution Equipment 
(subpart DD).
    (vi) Underground Coal Mines (subpart FF).
    (vii) Industrial Wastewater Treatment (subpart II).
    (viii) Imports and Exports of Equipment Pre-charged with 
Fluorinated GHGs or Containing Fluorinated GHGs in Closed-cell Foams 
(subpart QQ).
    (ix) Geologic Sequestration of Carbon Dioxide (subpart RR).
    (x) Manufacture of Electric Transmission and Distribution (subpart 
SS).
    (xi) Industrial Waste Landfills (subpart TT).
    (xii) Injection of Carbon Dioxide (subpart UU).
* * * * *
    (4) Unless otherwise stated, if the final day of any time period 
falls on a weekend or a Federal holiday, the time period shall be 
extended to the next business day.
    (c) * * *
    (5) * * *
    (ii) Quantity of each GHG from each applicable supply category in 
Table A-5 of this subpart, expressed in metric tons of each GHG. For 
fluorinated GHG, report quantities of all fluorinated GHG, including 
those not listed in Table A-1 of this subpart.
* * * * *
    (7) A brief description of each ``best available monitoring 
method'' used, the parameter measured using the method, and the time 
period during which the ``best available monitoring method'' was used, 
if applicable.
* * * * *
    (10) NAICS code(s) that apply to the facility or supplier.
    (i) Primary NAICS code. Report the NAICS code that most accurately 
describes the facility or supplier's primary product/activity/service. 
The primary product/activity/service is the principal source of revenue 
for the facility or supplier. A facility or supplier that has two 
distinct products/activities/services providing comparable revenue may 
report a second primary NAICS code.
    (ii) Additional NAICS code(s). Report all additional NAICS codes 
that describe all product(s)/activity(s)/service(s) at the facility or 
supplier that are not related to the principal source of revenue.
    (11) Legal name(s) and physical address(es) of the highest-level 
United States parent company(s) of the owners (or operators) of the 
facility or supplier and the percentage of ownership interest for each 
listed parent company as of December 31 of the year for which data are 
being reported according to the following instructions:
    (i) If the facility or supplier is entirely owned by a single 
United States company that is not owned by another company, provide 
that company's legal name and physical address as the United States 
parent company and report 100 percent ownership.
    (ii) If the facility or supplier is entirely owned by a single 
United States company that is, itself, owned by another company (e.g., 
it is a division or subsidiary of a higher-level company), provide the 
legal name and physical address of the highest-level company in the 
ownership hierarchy as the United States parent company and report 100 
percent ownership.
    (iii) If the facility or supplier is owned by more than one United 
States company (e.g., company A owns 40 percent, company B owns 35 
percent, and company C owns 25 percent), provide the legal names and 
physical addresses of all the highest-level companies with an ownership 
interest as the United States parent companies, and report the percent 
ownership of each company.
    (iv) If the facility or supplier is owned by a joint venture or a 
cooperative, the joint venture or cooperative is its own United States 
parent company. Provide the legal name and physical address of the 
joint venture or cooperative as the United States parent company, and 
report 100 percent ownership by the joint venture or cooperative.
    (v) If the facility or supplier is entirely owned by a foreign 
company, provide the legal name and physical address of the foreign 
company's highest-level company based in the United States as the 
United States parent company, and report 100 percent ownership.
    (vi) If the facility or supplier is partially owned by a foreign 
company and partially owned by one or more U.S. companies, provide the 
legal name and physical address of the foreign company's highest-level 
company based in the United States, along with the legal names and 
physical addresses of the other U.S. parent companies, and report the 
percent ownership of each of these companies.
    (vii) If the facility or supplier is a federally owned facility, 
report ``U.S. Government'' and do not report physical address or 
percent ownership.
* * * * *
    (g) Recordkeeping. * * * Retain all required records for at least 3 
years from the date of submission of the annual GHG report for the 
reporting year in which the record was generated. * * *
* * * * *
    4. Section 98.4 is amended by revising paragraph (m)(4) to read as 
follows:

Sec.  98.4  Authorization and responsibilities of the designated 
representative.

* * * * *
    (m) * * *
    (4) Any electronic submission covered by the certification in 
paragraph (m)(2)(v)(A) of this section and made in accordance with a 
notice of delegation effective under paragraph (m)(3) of this section 
shall be deemed to be an electronic submission certified, signed, and 
submitted by the designated representative or alternate designated 
representative submitting such notice of delegation.
    5. Section 98.6 is amended by revising the definitions of 
``Blowdown vent stack'', ``Supplier'', and ``United States parent 
company(s)'' to read as follows:

Sec.  98.6  Definitions.

* * * * *
    Blowdown vent stack emissions mean natural gas and/or 
CO2 released due to maintenance and/or blowdown operations 
including compressor blowdown and emergency shut-down (ESD) system 
testing. Emissions from emergency events are not included.
* * * * *
    Supplier means a producer, importer, or exporter in any supply 
category

[[Page 47408]]

included in Table A-5, as defined by the corresponding subpart of this 
part.
* * * * *
    United States parent company(s) means the highest-level United 
States company(s) with an ownership interest in the facility or 
supplier as of December 31 of the year for which data are being 
reported.
* * * * *
    6. Section 98.9 introductory text is revised to read as follows:

Sec.  98.9  Addresses.

    All requests, notifications, and communications to the 
Administrator pursuant to this part, other than submittal of the annual 
GHG report; the certificate of representation; and other requests, 
notifications or communications that can be submitted through the 
electronic greenhouse gas reporting tool, shall be submitted to the 
following address:
* * * * *
    7. Table A-3 to subpart A is amended by revising the entry for 
``Underground coal mines'' and for ``Electrical transmission and 
distribution equipment use'' to read as follows:

    Table A-3 of Subpart A of Part 98--Source Category List for Sec.
                               98.2(a)(1)
------------------------------------------------------------------------
 
-------------------------------------------------------------------------
        Source Categories \a\ Applicable in 2010 and Future Years
 
                              * * * * * * *
  Additional Source Categories \a\ Applicable in 2011 and Future Years
 
                              * * * * * * *
Electrical transmission and distribution equipment use at facilities
 where the total nameplate capacity of SF6 and PFC containing equipment
 exceeds 17,820 pounds, as determined under Sec.   98.301 (subpart DD).
Underground coal mines liberating 36,500,000 actual cubic feet of CH4 or
 more per year (subpart FF).
 
                              * * * * * * *
------------------------------------------------------------------------
\a\ Source categories are defined in each applicable subpart.

    8. Table A-5 to subpart A is amended by revising the entries for 
``Petroleum product suppliers (subpart MM)'' to read as follows:

   Table A-5 to Subpart A of Part 98--Supplier Category List for Sec.
                               98.2(a)(4)
------------------------------------------------------------------------
 
-------------------------------------------------------------------------
       Supplier Categories\a\ Applicable in 2010 and Future Years
 
                              * * * * * * *
Petroleum product suppliers (subpart MM):
    (A) All petroleum refineries that distill crude oil.
    (B) Importers of an annual quantity of petroleum products and
     natural gas liquids that is equivalent to 25,000 metric tons CO2e
     or more.
    (C) Exporters of an annual quantity of petroleum products and
     natural gas liquids that is equivalent to 25,000 metric tons CO2e
     or more.
 
                              * * * * * * *
------------------------------------------------------------------------
\a\ Suppliers are defined in each applicable subpart.

Subpart W--[Amended]

    9. Section 98.230 is amended by revising paragraph(a)(3)(ii) to 
read as follows:

Sec.  98.230  Definition of the source category.

    (a) * * *
    (3) * * *
    (ii) All processing facilities that do not fractionate with annual 
average throughput of 25 MMscf per day or greater.
* * * * *
    10. Section 98.232 is amended by revising paragraph (d) 
introductory text and paragraph (i) introductory text to read as 
follows:

Sec.  98.232  GHGs to report.

* * * * *
    (d) For onshore natural gas processing, report CO2, 
CH4, and N2O emissions from the following 
sources:
* * * * *
    (i) For natural gas distribution, report CO2 and 
CH4 emissions from the following sources:
* * * * *
    11. Section 98.233 is amended by:
    a. Revising the definition of ``GHGi'' in Equation W-1 
of paragraph (a).
    b. Revising the definition of ``GHGi'' in Equation W-2 
and W-2 in paragraph (c).
    c. Revising the first sentence of paragraphs (d)(2), (d)(3), and 
(d)(4).
    d. Revising paragraphs (e) introductory text, (e)(1) introductory 
text, (e)(1)(xi) introductory text, (e)(1)(xi)(A) through (C), and 
(e)(2) introductory text.
    e. Revising paragraph (f)(2) introductory text.
    f. In paragraph (f)(2), revising the introductory text, Equation W-
8, and definitions of Equation W-8.
    g. In paragraph (f)(3), revising Equation W-9 and the definitions 
of Equation W-9.
    h. In paragraph (h), revising the definitions of 
``Ea,n'', ``EFwo'', and ``Vf'' in 
Equation W-13.
    i. Removing paragraph (h)(1).
    j. Redesignating paragraphs (h)(2) and (h)(3) as paragraphs (h)(1) 
and (h)(2), respectively, and revising new paragraph (h)(1).
    k. Revising paragraphs (i) introductory text and (i)(2).
    l. Revising the definition of ``Vv'' in Equation W-14 of paragraph 
(i)(3).
    m. Revising paragraph (i)(4).
    n. Revising the first sentence of paragraph (j)(1) and revising 
paragraph (j)(1)(vii).
    o. Revising paragraphs (j)(2), (j)(3) introductory text, and (j)(4) 
introductory text.
    p. In paragraph (j)(5), revising Equation W-15, revising the 
definitions of ``EFi'' and ``Count'', and defining the use 
of ``1,000''.
    q. In paragraph (j)(8), revising Equation W-16, revising the 
definition

[[Page 47409]]

of ``En'', removing the definition of ``Et'', and defining the use of 
``8,760''.
    r. Revising paragraphs (k)(2) and (k)(4).
    s. Revising paragraph (q) introductory text.
    t. Revising the definition of ``[rho]i'' in Equation W-36 of 
paragraph (v).
    u. Revising paragraph (z) introductory text.
    v. In paragraph (z)(2)(iii), revising Equation W-39; adding 
Equations W-39A and W-39B; adding definitions for 
``Ea,CH4'', ``[eta]'', ``YCO2'', and 
``YCH4''; and revising the definitions of ``Yj'' 
and ``Rj''.
    w. Revising paragraph (z)(3).
    x. Removing paragraphs (z)(6)(i) through (z)(6)(iii).
    y. Redesignating paragraphs (z)(4), (z)(5), and (z)(6) as 
(z)(2)(iv), (z)(2)(v), and (z)(2)(vi), respectively.
    z. In newly redesignated paragraph (z)(2)(vi), revising Equation W-
40 and revising the definition of ``HHV''.

Sec.  98.233  Calculating GHG emissions.

* * * * *
    (a) * * *

GHGi = For onshore petroleum and natural gas production 
facilities, concentration of GHGi, CH4 or 
CO2, in produced natural gas as defined in paragraph 
(u)(2)(i) of this section; for facilities listed in Sec.  
98.230(a)(4) and (a)(5), GHGi equals 0.952 for 
CH4 and 1x10-\2\ for CO2.
* * * * *
    (c) * * *

GHGi = Concentration of GHGi, CH4 
or CO2, in produced natural gas as defined in paragraph 
(u)(2)(i) of this section.
* * * * *
    (d) * * *
    (2) Calculation Methodology 2. If CEMS is not available but a vent 
meter is installed, use the CO2 composition and annual 
volume of vent gas to calculate emissions using Equation W-3 of this 
section.
* * * * *
    (3) Calculation Methodology 3. If CEMS or a vent meter is not 
installed, you may use the inlet or outlet gas flow rate of the acid 
gas removal unit to calculate emissions for CO2 using 
Equation W-4 of this section.
* * * * *
    (4) Calculation Methodology 4. If CEMS or a vent meter is not 
installed, you may calculate emissions using any standard simulation 
software packages, such as AspenTech HYSYS[supreg] and API 4679 
AMINECalc, that uses the Peng-Robinson equation of state, and speciates 
CO2 emissions. * * *
* * * * *
    (e) Dehydrator vents. For dehydrator vents, calculate annual 
CH4, CO2 and N2O (when flared) 
emissions using any of the calculation methodologies described in 
paragraph (e) of this section.
    (1) Calculation Methodology 1. Calculate annual mass emissions from 
dehydrator vents with annual average daily throughput greater than or 
equal to 0.4 million standard cubic feet per day using a software 
program, such as AspenTech HYSYS[supreg] or GRI-GLYCalc, that uses the 
Peng-Robinson equation of state to calculate the equilibrium 
coefficient, speciates CH4 and CO2 emissions from 
dehydrators, and has provisions to include regenerator control devices, 
a separator flash tank, stripping gas and a gas injection pump or gas 
assist pump. A minimum of the following parameters determined by 
engineering estimate based on best available data must be used to 
characterize emissions from dehydrators:
* * * * *
    (xi) Wet natural gas composition. Determine this parameter by 
selecting one of the methods described under paragraph (e)(1)(xi) of 
this section.
    (A) Use the wet natural gas composition as defined in paragraph 
(u)(2)(i) or (u)(2)(ii) of this section.
    (B) If wet natural gas composition cannot be determined using 
paragraph (u)(2)(i) or (u)(2)(ii) of this section, select a 
representative analysis.
    (C) You may use an appropriate standard method published by a 
consensus-based standards organization if such a method exists or you 
may use an industry standard practice as specified in Sec.  98.234(b) 
to sample and analyze wet natural gas composition.
* * * * *
    (2) Calculation Methodology 2. Calculate annual CH4 and 
CO2 emissions from glycol dehydrators with annual average 
daily throughput less than 0.4 million cubic feet per day using 
Equation W-5 of this section: * * *
* * * * *
    (f) * * *
    (2) Calculation Methodology 2. Calculate the total emissions for 
well venting for liquids unloading using Equation W-8 of this section.
[GRAPHIC] [TIFF OMITTED] TP04AU11.033

Where:

Ea,n = Annual natural gas emissions at actual conditions, 
in cubic feet/year.
W = Number of wells with well venting for liquids unloading at the 
facility.
0.37x10-3 = {3.14 (pi)/4{time} /{14.7*144{time}  (psia 
converted to pounds per square feet).
CDW = Casing diameter for each well, in inches.
WDW = Well depth to first producing horizon for each 
well, in feet.
SPW = Shut-in pressure for each well, in pounds square 
inch atmosphere (psia).
VW = Number of vents per year per well.
SFRW = Average sales flow rate of each gas well in cubic 
feet per hour.
HRV,W = Hours that each well was left open to the 
atmosphere during each unloading event.
1.0 = Hours for average well to blowdown casing volume at shut-in 
pressure.
ZV,W = If HRV,W is less than 1.0 then 
ZV,W is equal to 0. If HRV,W is greater than 
or equal to 1.0 then ZV,W is equal to 1.
* * * * *
    (3) * * *
    [GRAPHIC] [TIFF OMITTED] TP04AU11.034
    

Where:

Ea,n = Annual natural gas emissions at actual conditions, 
in cubic feet/year.
W = Number of wells with well venting for liquids unloading at the 
facility.
0.37x10-3 = {3.14 (pi)/4{time} /{14.7*144{time}  (psia 
converted to pounds per square feet).
TDW = Tubing diameter for each well, in inches.
WDW = Tubing depth to plunger bumper for each well, in 
feet.

[[Page 47410]]

SPW = Sales line pressure for each well, in pounds per 
square inch atmospheric (psia).
NV = Number of vents per year per well.
SFRW = Average sales flow rate of each gas well in cubic 
feet per hour.
HRV,W = Hours that each well was left open to the 
atmosphere during each unloading event.
0.5 = Hours for average well to blowdown tubing volume at sales line 
pressure.
ZV,W = If HRV,W is less than 0.5 then 
ZV,W is equal to 0. If HRV,W is greater than 
or equal to 0.5 then ZV,W is equal to 1.
* * * * *
    (h) * * *

Es,n = Annual natural gas emissions in standard cubic 
feet from a gas well venting during well completions and workovers 
without hydraulic fracturing.
* * * * *
EFwo = Emission Factor for non-hydraulic fracture well 
workover venting in standard cubic feet per workover. 
EFwo = 3114 standard cubic feet per well workover without 
hydraulic fracturing.
* * * * *
Vf = Average daily gas production rate in standard cubic 
feet per hour of each well completion without hydraulic fracturing. 
This is the total annual gas production volume divided by total 
number of hours the wells produced to the sales line. For completed 
wells that have not established a production rate, you may use the 
average flow rate from the first 30 days of production. In the event 
that the well is completed less than 30 days from the end of the 
calendar year, the first 30 days of the production straddling the 
current and following calendar years shall be used.

    (1) Volumetric emissions for both CH4 and CO2 
shall be calculated from volumetric natural gas emissions using 
calculations in paragraphs (u) of this section. Mass emissions for both 
CH4 and CO2 shall be calculated from volumetric 
natural gas emissions using calculations in paragraphs (v) of this 
section.
    (2) Calculate annual emissions from gas well venting during well 
completions and workovers not involving hydraulic fracturing to flares 
as follows:
* * * * *
    (i) Blowdown vent stacks. Calculate CO2 and 
CH4 blowdown vent stack emissions from depressurizing 
equipment to the atmosphere (excluding depressurizing to a flare, over-
pressure relief, operating pressure control venting and blowdown of 
non-GHG gases; desiccant dehydrator blowdown venting before reloading 
is covered in paragraph (e)(5) of this section) as follows (Emissions 
from emergency events are not included.):
* * * * *
    (2) If the total physical volume between isolation valves is 
greater than or equal to 50 cubic feet, retain logs of the number of 
blowdowns for each equipment type (including but not limited to 
compressors, vessels, pipelines, headers, fractionators, and tanks). 
Blowdown volumes smaller than 50 standard cubic feet are exempt from 
reporting under paragraph (i) of this section.
    (3) * * *

Vv = Total physical volume of blowdown equipment chambers 
(including pipelines, compressors and vessels) between isolation 
valves in cubic feet.
* * * * *
    (4) Calculate both CH4 and CO2 volumetric and 
mass emissions using calculations in paragraph (u) and (v) of this 
section.
* * * * *
    (j) * * *
    (1) Calculation Methodology 1. For separators with annual average 
daily throughput of oil greater than or equal to 10 barrels per day. * 
* *
* * * * *
    (vii) Separator oil composition and Reid vapor pressure. If this 
data is not available, determine these parameters by selecting one of 
the methods described under paragraph (j)(1)(vii) of this section.
* * * * *
    (2) Calculation Methodology 2. Calculate annual CH4 and 
CO2 emissions from onshore production storage tanks for 
wellhead gas-liquid separators with annual average daily throughput of 
oil greater than or equal to 10 barrels per day by assuming that all of 
the CH4 and CO2 in solution at separator 
temperature and pressure is emitted from oil sent to storage tanks. You 
may use an appropriate standard method published by a consensus-based 
standards organization if such a method exists or you may use an 
industry standard practice as described in Sec.  98.234(b) to sample 
and analyze separator oil composition at separator pressure and 
temperature.
    (3) Calculation Methodology 3. For wells with annual average daily 
oil production greater than or equal to 10 barrels per day that flow 
directly to atmospheric storage tanks without passing through a 
wellhead separator, calculate annual CH4 and CO2 
emissions by either of the methods in paragraph (j)(3) of this section:
* * * * *
    (4) Calculation Methodology 4. For wells with annual average daily 
oil production greater than or equal to 10 barrels per day that flow to 
a separator not at the well pad, calculate annual CH4 and 
CO2 emissions by either of the methods in paragraph (j)(4) 
of this section:
* * * * *
    (5) * * *
    [GRAPHIC] [TIFF OMITTED] TP04AU11.035
    

Where:

Es,i = Annual total volumetric GHG emissions (either 
CO2 or CH4) at standard conditions in cubic 
feet.
EFi = Populations emission factor for separators or wells 
in thousand standard cubic feet per separator or well per year, for 
crude oil use 4.3 for CH4 and 2.9 for CO2 at 
68[deg]F and 14.7 psia, and for gas condensate use 17.8 for 
CH4 and 2.9 for CO2 at 68[deg]F and 14.7 psia.
Count = Total number of separators or wells with throughput less 
than 10 barrels per day.
1,000 = Conversion to cubic feet.
* * * * *
    (8) * * *
    [GRAPHIC] [TIFF OMITTED] TP04AU11.036
    

Where:
* * * * *
En = Storage tank emissions as determined in Calculation 
Methodologies 1, 2, or 4 in paragraphs (j)(1), (j)(2) and (j)(4) of 
this section (with wellhead separators) in cubic feet per year.
* * * * *

[[Page 47411]]

8,760 = Conversion to hourly emissions.
* * * * *
    (k) * * *
    (2) If the tank vapors are continuous for 5 minutes, or the 
acoustic leak detection device detects a leak, then use one of the 
following two methods in paragraph (k)(2) of this section to quantify 
annual emissions:
* * * * *
    (4) Calculate annual emissions from storage tanks to flares as 
follows:
    (i) Use the storage tank emissions volume and gas composition as 
determined in paragraphs (k)(1) through (k)(3) of this section.
    (ii) Use the calculation methodology of flare stacks in paragraph 
(n) of this section to determine storage tank emissions sent to a 
flare.
* * * * *
    (q) Leak detection and leaker emission factors. You must use the 
methods described in Sec.  98.234(a) to conduct leak detection(s) of 
equipment leaks from all sources listed in Sec.  98.232(d)(7), (e)(7), 
(f)(5), (g)(3), (h)(4), and (i)(1). This paragraph (q) applies to 
emissions sources in streams with gas content greater than 10 percent 
CH4 plus CO2 by weight. Emissions sources in 
streams with gas content less than 10 percent CH4 plus 
CO2 by weight do not need to be reported. Tubing systems 
equal to or less than one half inch diameter are exempt from the 
requirements of this paragraph (q) and do not need to be reported. If 
equipment leaks are detected for sources listed in this paragraph (q), 
calculate equipment leak emissions per source per reporting facility 
using Equation W-30 of this section for each source with equipment 
leaks.
* * * * *
    (v) * * *

[rho]i = Density of GHG i. Use 0.0520 kg/ft\3\ for CO2 
and N2O, and 0.0190 kg/ft\3\ for CH4 at 
68[deg]F and 14.7 psia or 0.0530 kg/ft\3\ for CO2 and 
N2O, and 0.0193 kg/ft\3\ for CH4 at 60[deg]F 
and 14.7 psia.
* * * * *
    (z) Onshore petroleum and natural gas production and natural gas 
distribution combustion emissions. Calculate CO2, 
CH4, and N2O combustion-related emissions from 
stationary or portable equipment, except as specified in paragraph 
(z)(3) of this section, as follows:
    (2) * * *
    (iii) * * *
    [GRAPHIC] [TIFF OMITTED] TP04AU11.037
    

Where:

* * * * *
Ea,CH4 = Contribution of annual CH4 emissions 
from portable or stationary fuel combustion sources in cubic feet, 
under actual conditions.
[eta] = Combustion efficiency for portable and stationary equipment 
determined based on engineering estimation.
* * * * *
Yj = Concentration of gas hydrocarbon constituents j 
(such as methane, ethane, propane, butane, and pentanes plus) in gas 
sent to combustion unit.
YCH4 = Concentration of methane constituent in gas sent 
to combustion unit.
YCO2 = Concentration of CO2 constituent in gas 
sent to combustion unit.
Rj = Number of carbon atoms in the gas hydrocarbon 
constituent j; 1 for methane, 2 for ethane, 3 for propane, 4 for 
butane, and 5 for pentanes plus) in gas sent to combustion unit.

    (iv) Calculate GHG volumetric emissions at standard conditions 
using calculations in paragraph (t) of this section.
    (v) Calculate both combustion-related CH4 and 
CO2 mass emissions from volumetric CH4 and 
CO2 emissions using calculation in paragraph (v) of this 
section.
    (vi) Calculate N2O mass emissions using Equation W-40 of 
this section.
[GRAPHIC] [TIFF OMITTED] TP04AU11.038

Where:

* * * * *
HHV = For the high heat value for field gas or process vent gas, use 
1.235 x 10-3 mmBtu/scf for HHV.
* * * * *
    (3) External fuel combustion sources with a rated heat capacity 
equal to or less than 5 mmBtu/hr do not need to report combustion 
emissions or include these emissions for threshold determination in 
Sec.  98.231(a). You must report the type and number of each external 
fuel combustion unit.
    12. Section 98.234 is amended by revising Equation W-41 of 
paragraph (e) to read as follows:

Sec.  98.234  Monitoring and QA/QC requirements.

* * * * *
    (e) * * *
    [GRAPHIC] [TIFF OMITTED] TP04AU11.039
    

Where:

p = Absolute pressure.
R = Universal gas constant.
T = Absolute temperature.
Vm = Molar volume.

[[Page 47412]]

[GRAPHIC] [TIFF OMITTED] TP04AU11.040

Where:

[omega] = Acentric factor of the species.
Tc = Critical temperature.
Pc = Critical pressure.
* * * * *
    13. Section 98.236 is amended by revising paragraphs (c)(6)(ii)(B) 
and (c)(7)(i).

Sec.  98.236  Data reporting requirements.

* * * * *
    (c) * * *
    (6) * * *
    (ii) * * *
    (B) Total count of workovers in calendar year that flare gas or 
vent gas to the atmosphere.
* * * * *
    (7) * * *
    (i) Total number of blowdowns per unique volume type in calendar 
year.
* * * * *
    14. Tables W-3 and W-4 to subpart W are amended by revising the 
entries for ``Low Continuous Bleed Pneumatic Device Vents'', ``High 
Continuous Bleed Pneumatic Device Vents'', and ``Intermittent Bleed 
Pneumatic Device Vents'' as follows:

  Table W-3 to Subpart W of Part 98--Default Total Hydrocarbon Emission
        Factors for Onshore Natural Gas Transmission Compression
------------------------------------------------------------------------
                                                  Emission factor  (scf/
  Onshore natural gas transmission compression       hour/component)
------------------------------------------------------------------------
       Leaker Emission Factors--Compressor Components, Gas Service
 
                              * * * * * * *
     Leaker Emission Factors--Non-Compressor Components, Gas Service
 
                              * * * * * * *
                Population Emission Factors--Gas Service
    Low Continuous Bleed Pneumatic Device Vents                     1.79
     \2\.......................................
 
    High Continuous Bleed Pneumatic Device                          20.1
     Vents \2\.................................
    Intermittent Bleed Pneumatic Device Vents                       20.1
     \2\.......................................
------------------------------------------------------------------------
\1\ Valves include control valves, block valves and regulator valves.
\2\ Emission Factor is in units of ``scf/hour/device''.

  Table W-4 to Subpart W of Part 98--Default Total Hydrocarbon Emission
               Factors for Underground Natural Gas Storage
------------------------------------------------------------------------
                                                  Emission factor  (scf/
        Underground natural gas storage              hour/component)
------------------------------------------------------------------------
          Leaker Emission Factors--Storage Station, Gas Service
 
                              * * * * * * *
       Population Emission Factors--Storage Wellheads, Gas Service
 
                              * * * * * * *
       Population Emission Factors--Other Components, Gas Service
    Low Continuous Bleed Pneumatic Device Vents                     1.79
     \2\.......................................
    High Continuous Bleed Pneumatic Device                          20.1
     Vents \2\.................................
    Intermittent Bleed Pneumatic Device Vents                       20.1
     \2\.......................................
------------------------------------------------------------------------
\1\ Valves include control valves, block valves and regulator valves.
\2\ Emission Factor is in units of ``scf/hour/device''.

Subpart FF--[Amended]

    15. Section 98.322 is amended by revising paragraph (f) to read as 
follows:

Sec.  98.322  GHGs to report.

* * * * *
    (f) An underground coal mine that is subject to this part because 
emissions from source categories described in Tables A-3, A-4 or A-5, 
or from stationary combustion (subpart C), is not required to report 
emissions under subpart FF of this part unless the coal mine liberates 
36,500,000 actual cubic

[[Page 47413]]

feet (acf) or more of methane per year from its ventilation system.
    16. Section 98.323 is amended by:
    a. Revising the definitions of ``V'', ``C'', and ``P'' in Equation 
FF-1 of paragraph (a).
    b. Revising the first sentence of paragraph (a)(2).
    c. Revising the definitions of ``Vi'', ``Ci'', Ti, and ``Pi'' in 
equation FF-3 of paragraph (b).
    d. Revising the first sentence of parapraph (b)(1).
    e. Revising paragraph (c) introductory text.

Sec.  98.323  Calculating GHG emissions.

    (a) * * *

V = Volumetric flow rate for the quarter (cfm) based on sampling or 
a flow rate meter. If a flow rate meter is used and the meter 
automatically corrects for temperature and pressure, replace 
``520[deg]R/T x P/1 atm'' with ``1''.
* * * * *
C = CH4 concentration of ventilation gas for the quarter 
(%).
* * * * *
P = Pressure at which flow is measured (atm) for the quarter. The 
annual average barometric pressure from the nearest NOAA weather 
service station may be used as a default.
* * * * *
    (2) Values of V, C, T, P, and fH2O, if applicable, must 
be based on measurements taken at least once each quarter with no fewer 
than 6 weeks between measurements. * * *
* * * * *
    (b) * * *

Vi = Measured volumetric flow rate for the days in the 
week when the degasification system is in operation at that 
monitoring point, based on sampling or a flow rate meter (cfm). If a 
flow rate meter is used and the meter automatically corrects for 
temperature and pressure, replace ``520[deg]R/Ti x 
Pi/1 atm'' with ``1''.
* * * * *
Ci = CH4 concentration of gas for the days in 
the week when the degasification system is in operation at that 
monitoring point (%).
* * * * *
Ti = Temperature at which flow is measured ([deg]R).
Pi = Pressure at which flow is measured (atm).
* * * * *
    (1) Values for V, C, T, P, and fH2O, if applicable, must be based 
on measurements taken at least once each calendar week with at least 3 
days between measurements. * * *
* * * * *
    (c) If gas from degasification system wells or ventilation shafts 
is sold, used onsite, or otherwise destroyed (including by flaring), 
you must calculate the quarterly CH4 destroyed for each 
destruction device and each point of offsite transport to a destruction 
device, using Equation FF-5 of this section. You must measure 
CH4 content and flow rate according to the provisions in 
Sec.  98.324, and calculate the methane routed to the destruction 
device (CH4) using either Eq. FF-1 or Eq. FF-3, as 
applicable.
* * * * *
    17. Section 98.324 is amended by:
    a. Revising paragraphs (b)(1) and (b)(2).
    b. Revising paragraph (c).
    c. Revising paragraph (d).
    d. Revising paragraph (e) introductory text.
    e. Revising paragraphs (g) and (h).

Sec.  98.324  Monitoring and QA/QC requirements.

* * * * *
    (b) * * *
    (1) Collect quarterly or more frequent grab samples (with no fewer 
than 6 weeks between measurements) for methane concentration and make 
quarterly measurements of flow rate, temperature, pressure, and 
moisture content, if applicable. The sampling and measurements must be 
made at the same locations as MSHA inspection samples are taken, and 
should be taken when the mine is operating under normal conditions. You 
must follow MSHA sampling procedures as set forth in the MSHA Handbook 
entitled, General Coal Mine Inspection Procedures and Inspection 
Tracking System Handbook Number: PH-08-V-1, January 1, 2008 
(incorporated by reference, see Sec.  98.7). You must record the date 
of sampling, flow, temperature, pressure, and moisture measurements, 
the methane concentration (percent), the bottle number of samples 
collected, and the location of the measurement or collection.
    (2) Obtain results of the quarterly (or more frequent) testing 
performed by MSHA for the methane flowrate. At the time and location of 
the MSHA sampling, make measurements of temperature, pressure and 
moisture content using the same procedures specified in paragraph 
(b)(1) of this section. If the MSHA data for methane flow is provided 
in the units of actual cubic feet of methane per day, the methane flow 
data is inserted into Equation FF-1 of this section in place of the 
value for V and the variables MCF, C/100%, and 1440 are removed from 
the equation.
* * * * *
    (c) For CH4 liberated at degasification systems, 
determine whether CH4 will be monitored from each well and 
gob gas vent hole, from a centralized monitoring point, or from a 
combination of the two options. Operators are allowed flexibility for 
aggregating emissions from more than one well or gob gas vent hole, as 
long as emissions from all are addressed, and the methodology for 
calculating total emissions is documented. Monitor both gas volume and 
methane concentration by one of the following two options:
    (1) Monitor emissions through the use of one or more continuous 
emissions monitoring systems (CEMS). If operators use CEMS as the basis 
for emissions reporting, they must provide documentation on the process 
for using data obtained from their CEMS to estimate emissions from 
their mine ventilation systems.
    (2) Collect weekly (once each calendar week, with at least three 
days between measurements) or more frequent samples, for all 
degasification wells and gob gas vent holes. Determine weekly or more 
frequent flow rates, methane concentration, temperature, and pressure 
from these degasification wells and gob gas vent holes. Methane 
composition should be determined either by submitting samples to a lab 
for analysis, or from the use of methanometers at the degasification 
well site. Follow the sampling protocols for sampling of methane 
emissions from ventilation shafts, as described in Sec.  98.324(b)(1). 
You must record the date of sampling, flow, temperature, pressure, and 
moisture measurements, the methane concentration (percent), the bottle 
number of samples collected, and the location of the measurement or 
collection.
    (3) If the CH4 concentration is determined on a dry 
basis and flow is determined on a wet basis or CH4 
concentration is determined on a wet basis and flow is determined on a 
dry basis, and the flow meter does not automatically correct for 
moisture content, determine the moisture content in the gas in a 
location near or representative of the location of:
    (i) The gas flow meter at least once each calendar week; if 
measuring with CEMS. If only one measurement is made each calendar 
week, there must be at least three days between measurements; and
    (ii) The grab sample, if using grab samples, at the time of the 
sample.
    (d) Monitoring must adhere to one of the methods specified in 
paragraphs (d)(1) through (d)(2) of this section.
    (1) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography; ASTM D1946-90 (Reapproved 2006), Standard 
Practice

[[Page 47414]]

for Analysis of Reformed Gas by Gas Chromatography; ASTM D4891-89 
(Reapproved 2006), Standard Test Method for Heating Value of Gases in 
Natural Gas Range by Stoichiometric Combustion; or ASTM UOP539-97 
Refinery Gas Analysis by Gas Chromatography (incorporated by reference, 
see Sec.  98.7).
    (2) As an alternative to the gas chromatography methods provided in 
paragraph (d)(1) of this section, you may use gaseous organic 
concentration analyzers and a correction factor to calculate the 
CH4 concentration following the requirements in paragraphs 
(d)(2)(i) through (d)(2)(iii) of this section.
    (i) Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to 
determine gaseous organic concentration as required in Sec.  98.323 and 
in paragraphs (b) and (c) of this section. You must calibrate the 
instrument with CH4 and determine the total gaseous organic 
concentration as carbon (or as CH4; K = 1 in Equation 25A-1 
of Method 25A at 40 CFR part 60, appendix A-7).
    (ii) Determine a correction factor that will be used with the 
gaseoue organic concentrations measured in paragraph (i) of this 
section. The correction factor must be determined at the routine 
sampling location no less frequently than once a reporting year 
following the requirements in paragraphs (d)(2)(ii)(A) through 
(d)(2)(ii)(C) of this section.
    (A) Take a minimum of three grab samples of the gas with a minimum 
of 20 minutes between samples and determine the methane composition of 
the gas using one of the methods specified in paragraph (d)(1) of this 
section.
    (B) As soon as practical after each grab sample is collected and 
prior to the collection of a subsequent grab sample, determine the 
gaseous organic concentration of the gas using either Method 25A or 25B 
at 40 CFR part 60, appendix A-7 as specified in paragraph (d)(2)(i) of 
this section.
    (C) Determine the arithmetic average methane concentration and the 
arithmetic average gaseous organic concentration of the samples 
analyzed according to paragraphs (d)(2)(ii)(A) and (d)(2)(ii)(B) of 
this section, respectively, and calculate the non-methane organic 
carbon correction factor as the ratio of the average methane 
concentration to the average total gaseous organic concentration. If 
the ratio exceeds 1, use 1 for the correction factor.
    (iii) Calculate the CH4 concentration as specified in 
Equation FF-9 of this section:
[GRAPHIC] [TIFF OMITTED] TP04AU11.041

Where:

CCH4 = Methane (CH4) concentration in the gas 
(volume %) for use in Equations FF-1 and FF-3 of this subpart.
fNMOC = Correction factor from the most recent 
determination of the correction factor as specified in paragraph 
(d)(2)(ii) of this section (unitless).
CTGOC = Gaseous organic carbon concentration measured 
using Method 25A or 25B at 40 CFR part 60, appendix A-7 during 
routine monitoring of the gas (volume %).

    (e) All flow meters and gas composition monitors that are used to 
provide data for the GHG emissions calculations shall be calibrated 
prior to the first reporting year, using the applicable methods 
specified in paragraphs (d), and (e)(1) through (e)(7) of this section. 
Alternatively, calibration procedures specified by the flow meter 
manufacturer may be used. Flow meters and gas composition monitors 
shall be recalibrated either at the minimum frequency specified by the 
manufacturer or annually. The operator shall operate, maintain, and 
calibrate a gas composition monitor capable of measuring the 
concentration of CH4 in the gas using one of the methods 
specified in paragraph (d) of this section. The operator shall operate, 
maintain, and calibrate the flow meter using any of the following test 
methods or follow the procedures specified by the flow meter 
manufacturer. Flow meters must meet the accuracy requirements in Sec.  
98.3(i).
* * * * *
    (g) All temperature, pressure, and moisture content monitors must 
be operated and calibrated using the procedures and frequencies 
specified by the manufacturer.
    (h) If applicable, the owner or operator shall document the 
procedures used to ensure the accuracy of gas flow rate, gas 
composition, temperature, pressure, and moisture content measurements. 
These procedures include, but are not limited to, calibration of flow 
meters, and other measurement devices. The estimated accuracy of 
measurements, and the technical basis for the estimated accuracy shall 
be recorded.
    18. Section 98.325 is amended by revising the first sentence of 
paragraph (b) as follows:

Sec.  98.325  Procedures for estimating missing data.

* * * * *
    (b) For each missing value of CH4 concentration, flow 
rate, temperature, pressure, and moisture content for ventilation and 
degasification systems, the substitute data value shall be the 
arithmetic average of the quality-assured values of that parameter 
immediately preceding and immediately following the missing data 
incident. * * *
    Section 98.326 is amended by:
    a. Revising paragraph (f).
    b. Revising paragraph (h).
    c. Revising paragraph (j).
    d. Revising paragraph (k).
    e. Revising paragraph (o).

Sec.  98.326  Data reporting requirements.

* * * * *
    (f) Quarterly volumetric flow rate for each ventilation monitoring 
point (scfm), date and location of each measurement, and method of 
measurement (quarterly sampling or continuous monitoring), used in 
Equation FF-1.
* * * * *
    (h) Weekly volumetric flow rate used to calculate CH4 
liberated from degasification systems (cfm) and method of measurement 
(sampling or continuous monitoring), used in Equation FF-3.
* * * * *
    (j) Weekly volumetric flow rate used to calculate CH4 
destruction for each destruction device and each point of offsite 
transport (cfm).
    (k) Weekly CH4 concentration (%) used to calculate 
CH4 flow to each destruction device and each point of 
offsite transport (C).
* * * * *
    (o) Temperatures ([deg]R), pressure (atm), and moisture content 
used in Eq. FF-1 and FF-3, and the gaseous organic concentration 
correction factor, if Equation FF-9 was required.
* * * * *

Subpart II--[Amended]

    19. Section 98.350 is amended by revising the first sentence of 
paragraph (b) introductory text to read as follows:

Sec.  98.350  Definition of Source Category

* * * * *
    (b) An anaerobic process is a procedure in which organic matter in 
wastewater, wastewater treatment sludge, or other material is degraded 
by

[[Page 47415]]

micro-organisms in the absence of oxygen, resulting in the generation 
of CO2 and CH4. * * *
* * * * *
    20. Section 98.352 is amended by revising paragraph (d) as follows:

Sec.  98.352  GHGs to report.

* * * * *
    (d) You must report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the emissions of CO2, 
CH4, and N2O from each stationary combustion unit 
associated with the biogas destruction device, if present, by following 
the requirements of subpart C of this part.
    21. Section 98.353 is amended by:
    a. Revising paragraph (a)(2).
    b. Revising paragraph (c) introductory text and paragraph (c)(1) 
introductory text.
    c. Revising the definitions of ``Rn'', ``Tm'', and ``Pm'' in 
Equation II-4 of paragraph (c)(1).
    d. Revising paragraph (c)(2).
    e. Revising paragraph (d) introductory text.
    f. Revising the definition of ``Rn'' in Equation II-5 in paragraph 
(d)(1).
    g. Revising Equation II-6 and revising the definition of 
``CH4En'', ``Rn'', ``DE1'', 
and ``fDest--1'' in paragraph (d)(2).

Sec.  98.353  Calculating GHG emissions.

    (a) * * *
    (2) If you measure the concentration of organic material entering 
an anaerobic reactor or anaerobic lagoon using methods for the 
determination of 5-day biochemical oxygen demand (BOD5), 
then estimate annual mass of CH4 generated using Equation 
II-2 of this section.
* * * * *
    (c) For each anaerobic sludge digester, anaerobic reactor, or 
anaerobic lagoon from which some biogas is recovered, estimate the 
annual mass of CH4 recovered according to the requirements 
in paragraphs (c)(1) and (c)(2) of this section. To estimate the annual 
mass of CH4 recovered, you must continuously monitor biogas 
flow rate and determine the volume of biogas each week and the 
cumulative volume of biogas each year that is collected and routed to a 
destruction device as specified in Sec.  98.354(h). If the gas flow 
meter is not equipped with automatic correction for temperature, 
pressure, or, if necessary, moisture content, you must determine these 
parameters as specified in paragraph (c)(2)(ii) of this section.
    (1) If you continuously monitor CH4 concentration (and 
if necessary, temperature, pressure, and moisture content required as 
specified in Sec.  98.354(f)) of the biogas that is collected and 
routed to a destruction device using a monitoring meter specifically 
for CH4 gas, as specified in Sec.  98.354(g), you must use 
this monitoring system and calculate the quantity of CH4 
recovered for destruction using Equation II-4 of this section. A fully 
integrated system that directly reports CH4 quantity 
requires only the summing of results of all monitoring periods for a 
given year.
* * * * *

Rn = Annual quantity of CH4 recovered from the 
nth anaerobic reactor, sludge digester, or lagoon (metric tons 
CH4/yr)
* * * * *
Tm = Average temperature at which flow is measured for 
the measurement period ([deg]R). If the flow rate meter 
automatically corrects for temperature to 520[deg] R, replace 
``520[deg] R/Tm'' with ``1''.
Pm = Average pressure at which flow is measured for the 
measurement period (atm). If the flow rate meter automatically 
corrects for pressure to 1 atm, replace ``Pm/1'' with 
``1''.
* * * * *
    (2) If you do not continuously monitor CH4 concentration 
according to paragraph(c)(1) of this section, you must determine the 
CH4 concentration, temperature, pressure, and, if necessary, 
moisture content of the biogas that is collected and routed to a 
destruction device according to the requirements in paragraphs 
(c)(2)(i) through (c)(2)(ii) of this section and calculate the quantity 
of CH4 recovered for destruction using Equation II-4 of this 
section.
    (i) Determine the CH4 concentration in the biogas that 
is collected and routed to a destruction device in a location near or 
representative of the location of the gas flow meter at least once each 
calendar week; if only one measurement is made each calendar week, 
there must be least three days between measurements. For a given 
calendar week, you are not required to determine CH4 
concentration if the cumulative volume of biogas for that calendar 
week, determined as specified in paragraph (c) of this section, is 
zero.
    (ii) If the gas flow meter is not equipped with automatic 
correction for temperature, pressure, or, if necessary, moisture 
content:
    (A) Determine the temperature and pressure in the biogas that is 
collected and routed to a destruction device in a location near or 
representative of the location of the gas flow meter at least once each 
calendar week; if only one measurement is made each calendar week, 
there must be at least three days between measurements.
    (B) If the CH4 concentration is determined on a dry 
basis and biogas flow is determined on a wet basis, or CH4 
concentration is determined on a wet basis and biogas flow is 
determined on a dry basis, and the flow meter does not automatically 
correct for moisture content, determine the moisture content in the 
biogas that is collected and routed to a destruction device in a 
location near or representative of the location of the gas flow meter 
at least once each calendar week that the cumulative biogas flow 
measured as specified in Sec.  98.354(h) is greater than zero; if only 
one measurement is made each calendar week, there must be at least 
three days between measurements.
    (d) For each anaerobic sludge digester, anaerobic reactor, or 
anaerobic lagoon from which some quantity of biogas is recovered, you 
must estimate both the annual mass of CH4 that is generated, 
but not recovered, according to paragraph (d)(1) of this section and 
the annual mass of CH4 emitted according to paragraph (d)(2) 
of this section.
    (1) * * *

Rn = Annual quantity of CH4 recovered from the 
nth anaerobic reactor, anaerobic lagoon, or anaerobic sludge 
digester, as calculated in Equation II-4 of this section (metric 
tons CH4).
* * * * *
    (2) For each anaerobic sludge digester, anaerobic reactor, or 
anaerobic lagoon from which some quantity of biogas is recovered, 
estimate the annual mass of CH4 emitted using Equation II-6 
of this section.
[GRAPHIC] [TIFF OMITTED] TP04AU11.042

Where:

CH4En = Annual quantity of CH4 
emitted from the process n from which biogas is recovered (metric 
tons).
* * * * *

Rn = Annual quantity of CH4 recovered from the 
nth anaerobic reactor or anaerobic sludge digester, as calculated in 
Equation II-4 of this section (metric tons CH4).
DE1 = Primary destruction device CH4 
destruction efficiency (lesser of manufacturer's specified 
destruction efficiency and 0.99). If the biogas is

[[Page 47416]]

transported off-site for destruction, use DE=1.
fDest--1 = Fraction of hours the primary destruction 
device was operating (device operating hours/hours in the year). If 
the biogas is transported off-site for destruction, use 
fDest=1.
* * * * *
    22. Section 98.354 is amended by:
    a. Revising the second sentence of paragraph (c).
    b. Revising paragraph (d) introductory text.
    c. Revising paragraph (f).
    d. Revising paragraph (g) introductory text.
    e. Revising paragraph (h) introductory text and paragraph (h)(5).
    f. Revising paragraph (k).

Sec.  98.354  Monitoring and QA/QC requirements.

    (c) * * * You must collect and analyze samples for COD or 
BOD5 concentration at least once each calendar week that the 
anaerobic wastewater treatment process is operating; if only one 
measurement is made each calendar week, there must be at least three 
days between measurements. * * *
    (d) You must measure the flowrate of wastewater entering anaerobic 
wastewater treatment process at least once each calendar week that the 
process is operating; if only one measurement is made each calendar 
week, there must be at least three days between measurements. You must 
measure the flowrate for the 24-hour period for which you collect 
samples analyzed for COD or BOD5 concentration. The flow 
measurement location must correspond to the location used to collect 
samples analyzed for COD or BOD5 concentration. You must 
measure the flowrate using one of the methods specified in paragraphs 
(d)(1) through (d)(5) of this section or as specified by the 
manufacturer.
* * * * *
    (f) For each anaerobic process (such as anaerobic reactor, sludge 
digester, or lagoon) from which biogas is recovered, you must make the 
measurements or determinations specified in paragraphs (f)(1) through 
(f)(3) of this section.
    (1) You must continuously measure the biogas flow rate as specified 
in paragraph (h) of this section and determine the cumulative volume of 
biogas recovered.
    (2) You must determine the CH4 concentration of the 
recovered biogas as specified in paragraph (g) of this section at a 
location near or representative of the location of the gas flow meter. 
You must determine CH4 concentration either continuously or 
intermittently. If you determine the concentration intermittently, you 
must determine the concentration at least once each calendar week that 
the cumulative biogas flow measured as specified in paragraph (h) of 
this section is greater than zero, with at least three days between 
measurements.
    (3) As specified in Sec.  98.353(c) and paragraph (h) of this 
section, you must determine temperature, pressure, and moisture content 
as necessary to accurately determine the biogas flow rate and 
CH4 concentration. You must determine temperature and 
pressure if the gas flow meter or gas composition monitor do not 
automatically correct for temperature or pressure. You must measure 
moisture content of the recovered biogas if the biogas flow rate is 
measured on a wet basis and the CH4 concentration is 
measured on a dry basis. You must also measure the moisture content of 
the recovered biogas if the biogas flow rate is measured on a dry basis 
and the CH4 concentration is measured on a wet basis.
    (g) For each anaerobic process (such as an anaerobic reactor, 
sludge digester, or lagoon) from which biogas is recovered, operate, 
maintain, and calibrate a gas composition monitor capable of measuring 
the concentration of CH4 in the recovered biogas using one 
of the methods specified in paragraphs (g)(1) through (g)(6) of this 
section or as specified by the manufacturer.
* * * * *
    (h) For each anaerobic process (such as an anaerobic reactor, 
sludge digester, or lagoon) from which biogas is recovered, install, 
operate, maintain, and calibrate a gas flow meter capable of 
continuously measuring the volumetric flow rate of the recovered biogas 
using one of the methods specified in paragraphs (h)(1) through (h)(8) 
of this section or as specified by the manufacturer. Recalibrate each 
gas flow meter either biennially (every 2 years) or at the minimum 
frequency specified by the manufacturer. Except as provided in Sec.  
98.353(c)(2)(iii), each gas flow meter must be capable of correcting 
for the temperature and pressure and, if necessary, moisture content.
* * * * *
    (5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of 
Coriolis Mass Flowmeters (incorporated by reference, see Sec.  98.7). 
The mass flow must be corrected to volumetric flow based on the 
measured temperature, pressure, and biogas composition.
* * * * *
    (k) If applicable, the owner or operator must document the 
procedures used to ensure the accuracy of measurements of COD or 
BOD5 concentration, wastewater flow rate, biogas flow rate, 
biogas composition, temperature, pressure, and moisture content. These 
procedures include, but are not limited to, calibration of gas flow 
meters, and other measurement devices. The estimated accuracy of 
measurements made with these devices must also be recorded, and the 
technical basis for these estimates must be documented.
    23. Section 98.355 is amended by revising paragraph (b) to read as 
follows:

Sec.  98.355  Procedures for estimating missing data.

* * * * *
    (b) For each missing value of the CH4 content or biogas 
flow rates, the substitute data value must be the arithmetic average of 
the quality-assured values of that parameter immediately preceding and 
immediately following the missing data incident.
* * * * *
    24. Section 98.356 is amended by:
    a. Revising paragraph (a) introductory text.
    b. Revising paragraphs (b)(3) and (b)(4).
    c. Revising paragraph (d) introductory text and paragraphs (d)(2), 
(d)(4), (d)(6), and (d)(8).

Sec.  98.356  Data reporting requirements.

    (a) A description or diagram of the industrial wastewater treatment 
system, identifying the processes used to treat industrial wastewater 
and industrial wastewater treatment sludge. Indicate how the processes 
are related to each other and identify the anaerobic processes. Provide 
a unique identifier for each anaerobic process, indicate the average 
depth in meters of each anaerobic lagoon, and indicate whether biogas 
generated by each anaerobic process is recovered. The anaerobic 
processes must be identified as:
* * * * *
    (b) * * *
    (3) Maximum CH4 production potential (B0) 
used as an input to Equation II-1 or II-2 of this subpart, from Table 
II-1.
    (4) Methane conversion factor (MCF) used as an input to Equation 
II-1 or II-2 of this subpart, from Table II-1.
* * * * *
    (d) For each anaerobic wastewater treatment process and anaerobic 
sludge digester from which some biogas is recovered, you must report:
* * * * *
    (2) Total weekly volumetric biogas flow for each week (up to 52 
weeks/

[[Page 47417]]

year) that biogas is collected for destruction.
* * * * *
    (4) Weekly average biogas temperature for each week at which flow 
is measured for biogas collected for destruction, or statement that 
temperature is incorporated into monitoring equipment internal 
calcultations.
* * * * *
    (6) Weekly average biogas pressure for each week at which flow is 
measured for biogas collected for destruction, or statement that 
pressure is incorporated into monitoring equipment internal 
calcultations.
* * * * *
    (8) Whether destruction occurs at the facility or off-site. If 
destruction occurs at the facility, also report whether a back-up 
destruction device is present at the facility, the annual operating 
hours for the primary destruction device, the annual operating hours 
for the back-up destruction device (if present), the destruction 
efficiency for the primary destruction device, and the destruction 
efficiency for the back-up destruction device (if present).
* * * * *

Subpart OO--[Amended]

    25. Section 98.416 is amended by removing and reserving paragraphs 
(a)(8) and (a)(9) and revising paragraph (a)(10) to read as follows:

Sec.  98.416  Data reporting requirements.

* * * * *
    (a) * * *
    (8) [Reserved]
    (9) [Reserved]
    (10) Mass in metric tons of any fluorinated GHG or nitrous oxide 
fed into the transformation process, by process.
* * * * *
    26. Section 98.417 is amended by adding paragraphs (a)(3) and 
(a)(4) to read as follows:

Sec.  98.417  Records that must be retained.

    (a) * * *
    (3) Dated records of the total mass in metric tons of each reactant 
fed into the F-GHG or nitrous oxide production process, by process.
    (4) Dated records of the total mass in metric tons of the 
reactants, by-products, and other wastes permanently removed from the 
F-GHG or nitrous oxide production process, by process.
* * * * *

Subpart RR--[Amended]

    27. Section 98.442 is amended by revising paragraphs (e) and (f) to 
read as follows:

Sec.  98.442  GHGs to report.

* * * * *
    (e) Mass of CO2 emissions from equipment leaks and 
vented emissions of CO2 from surface equipment located 
between the injection flow meter and the injection wellhead.
    (f) Mass of CO2 emissions from equipment leaks and 
vented emissions of CO2 from surface equipment located 
between the production flow meter and the production wellhead.
* * * * *
    28. Section 98.443 is amended by:
    a. Revising paragraph (d) introductory text.
    b. Revising paragraph (d)(3).
    c. Revising the definition of ``CO2FI'' and 
``CO2FP'' in Equation RR-11 of paragraph (f)(1).
    d. Revising the definition of ``CO2FI'' in Equation RR-
12 of paragraph (f)(2).

Sec.  98.443  Calculating CO2 geologic sequestration.

* * * * *
    (d) You must calculate the annual mass of CO2 produced 
from oil or gas production wells or from other fluid wells for each 
separator that sends a stream of gas into a recycle or end use system 
in accordance with the procedures specified in paragraphs (d)(1) 
through (d)(3) of this section. You must account for any CO2 
that is produced and not processed through a separator. You must 
account only for wells that produce the CO2 that was 
injected into the well or wells covered by this source category.
* * * * *
    (3) To aggregate production data, you must sum the mass of all of 
the CO2 separated at each gas-liquid separator in accordance 
with the procedure specified in Equation RR-9 of this section. You must 
assume that the total CO2 measured at the separator(s) 
represents a percentage of the total CO2 produced. In order 
to account for the percentage of CO2 produced that is 
estimated to remain with the produced oil or other fluid, you must 
multiply the quarterly mass of CO2 measured at the 
separator(s) by a percentage estimated using a methodology in your 
approved MRV plan. If fluids containing CO2 from injection 
wells covered under this source category are produced and not processed 
through a gas-liquid separator, the concentration of CO2 in 
the produced fluids must be measured at a flow meter located prior to 
reinjection or reuse using methods in Sec.  98.444(f)(1). The 
considerations you intend to use to calculate CO2 from 
produced fluids for the mass balance equation must be described in your 
approved MRV plan in accordance with Sec.  98.448(d)(5).
* * * * *
    (f) * * *
    (1) * * *

CO2FI = Total annual CO2 mass emitted (metric 
tons) from equipment leaks and vented emissions of CO2 
from equipment located on the surface between the flow meter used to 
measure injection quantity and the injection wellhead, for which a 
calculation procedure is provided in subpart W of this part.
CO2FP = Total annual CO2 mass emitted (metric 
tons) from equipment leaks and vented emissions of CO2 
from equipment located on the surface between the production 
wellhead and the flow meter used to measure production quantity, for 
which a calculation procedure is provided in subpart W of this part.
* * * * *
    (2) * * *

CO2FI = Total annual CO2 mass emitted (metric 
tons) from equipment leaks and vented emissions of CO2 
from equipment located on the surface between the flow meter used to 
measure injection quantity and the injection wellhead.

    29. Section 98.444 is amended by revising the heading of paragraph 
(d) to read as follows:

Sec.  98.444  Monitoring and QA/QC requirements.

* * * * *
    (d) CO2 emissions from equipment leaks and vented emissions of CO2. 
* * *
* * * * *
    30. Section 98.445 is amended by revising paragraph (e) to read as 
follows:

Sec.  98.445  Procedures for estimating missing data.

* * * * *
    (e) For any values associated with CO2 emissions from 
equipment leaks and vented emissions of CO2 from surface 
equipment at the facility that are reported in this subpart, missing 
data estimation procedures should be followed in accordance with those 
specified in subpart W of this part.
* * * * *
    31. Section 98.446 is amended by:
    a. Revising paragraph (a)(2) introductory text and (a)(3) 
introductory text.
    b. Revising paragraph (e).
    c. Revising paragraph (f) introductory text.
    d. Revising paragraph (f)(1)(vii).
    e. Revising paragraphs (f)(3).

[[Page 47418]]

Sec.  98.446  Data reporting requirements.

    (a) * * *
    (2) If a volumetric flow meter is used to receive CO2 
report the following unless you reported yes to paragraph (a)(4) of 
this section:
* * * * *
    (3) If a mass flow meter is used to receive CO2 report 
the following unless you reported yes to paragraph (a)(4) of this 
section:
* * * * *
    (e) Report the date that you began collecting data for calculating 
total amount sequestered according to Sec.  98.448(a)(7) of this 
subpart.
    (f) Report the following. If the date specified in paragraph (e) of 
this section is during the reporting year for this annual report, 
report the following starting on the date specified in paragraph (e) of 
this section.
    (1) * * *
    (vii) The standard used to calculate each value in paragraphs 
(f)(1)(ii) through (f)(1)(iv) of this section.
* * * * *
    (3) For CO2 emissions from equipment leaks and vented 
emissions of CO2, report the following:
    (i) The mass of CO2 emitted (in metric tons) annually 
from equipment leaks and vented emissions of CO2 from 
equipment located on the surface between the flow meter used to measure 
injection quantity and the injection wellhead.
    (ii) The mass of CO2 emitted (in metric tons) annually 
from equipment leaks and vented emissions of CO2 from 
equipment located on the surface between the production wellhead and 
the flow meter used to measure production quantity.
* * * * *
    32. Section 98.447 is amended by revising paragraphs (a)(5) and 
(a)(6) to read as follows:

Sec.  98.447  Records that must be retained.

    (a) * * *
    (5) Annual records of information used to calculate the 
CO2 emitted from equipment leaks and vented emissions of 
CO2 from equipment located on the surface between the flow 
meter used to measure injection quantity and the injection wellhead.
    (6) Annual records of information used to calculate the 
CO2 emitted from equipment leaks and vented emissions of 
CO2 from equipment located on the surface between the 
production wellhead and the flow meter used to measure production 
quantity.
* * * * *
    33. Section 98.448 is amended by revising paragraphs (a)(5) and (e) 
to read as follows:

Sec.  98.448  Geologic sequestration monitoring, reporting, and 
verification (MRV) plan.

    (a) * * *
    (5) A summary of the considerations you intend to use to calculate 
site-specific variables for the mass balance equation. This includes, 
but is not limited to, considerations for calculating CO2 
emissions from equipment leaks and vented emissions of CO2 
between the injection flow meter and injection well and/or the 
production flow meter and production well, and considerations for 
calculating CO2 in produced fluids.
* * * * *
    (e) Revised MRV plan. The requirements of paragraph (c) of this 
section apply to any submission of a revised MRV plan. You must 
continue reporting under your currently approved plan while awaiting 
approval of a revised MRV plan.
* * * * *
    34. Section 98.449 is amended by revising the definition of 
``CO2 received'' to read as follows:

Sec.  98.449  Definitions.

* * * * *
    CO2 received means the CO2 stream that you 
receive to be injected for the first time into a well on your facility 
that is covered by this subpart. CO2 received includes, but 
is not limited to, a CO2 stream from a production process 
unit inside your facility and a CO2 stream that was injected 
into a well on another facility, removed from a discontinued enhanced 
oil or natural gas or other production well, and transferred to your 
facility.
* * * * *

Subpart TT--[Amended]

    35. Section 98.460 is amended by revising paragraphs (c)(1) and 
(c)(2)(i) to read as follows:

Sec.  98.460  Definition of the source category.

* * * * *
    (c) * * *
    (1) Construction and demolition waste landfills.
    (2) * * *
    (i) Coal combustion or incinerator ash (e.g., fly ash).
* * * * *
    36. Section 98.463 is amended by:
    a. In paragraph (a)(1), revising Equation TT-1 and revising the 
definitions of ``GCH4'', ``DOCx'', ``MCF'', and 
``Fx''.
    b. Revising paragraph (a)(2) introductory text.
    c. Revising paragraph (a)(2)(ii)(C).
    d. In paragraph (a)(2)(ii)(C), revising the definitions of 
``Wx'', ``LFC'', and ``YrData'' in Equation TT-4.

Sec.  98.463  Calculating GHG emissions.

    (a) * * *
    (1) * * *
    [GRAPHIC] [TIFF OMITTED] TP04AU11.043
    

Where:

GCH4 = Modeled methane generation in reporting year T 
(metric tons CH4).
* * * * *
DOCx = Degradable organic carbon for waste disposed in 
year X from Table TT-1 of this subpart or from measurement data [as 
specified in paragraph (a)(3) of this section], if available 
[fraction (metric tons C/metric ton waste)].
* * * * *
MCF = Methane correction factor (fraction). Use the default value of 
1 unless there is active aeration of waste within the landfill 
during the reporting year. If there is active aeration of waste 
within the landfill during the reporting year, use either the 
default value of 1 or select an alternative value no less than 0.5 
based on site-specific aeration parameters.
F = Fraction by volume of CH4 in landfill gas (fraction, 
dry basis, corrected to 0% oxygen). If you have a gas collection 
system, use the annual average CH4 concentration from 
measurement data for the current reporting year; otherwise, use the 
default value of 0.5.
* * * * *
    (2) Waste stream quantities. Determine annual waste quantities as 
specified in paragraphs (a)(2)(i) through (ii) of this section for each 
year starting with January 1, 1960 or the year the landfills first 
accepted waste if after January 1, 1960, up until the most recent 
reporting year. The choice of method for determining waste quantities 
will vary according to the availability of historical data. Beginning 
in the first emissions reporting year (2011 or later) and for each year 
thereafter, use the

[[Page 47419]]

procedures in paragraph (a)(2)(i) of this section to determine waste 
stream quantities. These procedures should also be used for any year 
prior to the first emissions reporting year for which the data are 
available. For other historical years, use paragraph (a)(2)(i) of this 
section, where waste disposal records are available, and use the 
procedures outlined in paragraph (a)(2)(ii) of this section when waste 
disposal records are unavailable, to determine waste stream quantities. 
Historical disposal quantities deposited (i.e., prior to the first year 
in which monitoring begins) should only be determined once, as part of 
the first annual report, and the same values should be used for all 
subsequent annual reports, supplemented by the next year's data on new 
waste disposal.
* * * * *
    (ii) * * *
    (C) For any year in which historic production or processing data 
are not available such that historic waste quantities cannot be 
estimated using Equation TT-3 of this section, calculate an average 
annual bulk waste disposal quantity using Equation TT-4 of this 
section.
* * * * *
Wx = Quantity of waste placed in the landfill in year X 
(metric tons, wet basis). This annual bulk waste disposal quantity 
applies for all years from ``YrOpen'' to ``YrData'' inclusive.
LFC = Capacity of the landfill used (or the total quantity of waste-
in-place) at the end of the ``YrData'' from design drawings or 
engineering estimates (metric tons). For closed landfills for which 
waste quantity data are not available, use the landfill's design 
capacity.
YrData = The year prior to the year when waste disposal data are 
first available from company records or from Equation TT-3 of this 
section. For landfills for which waste quantity data are not 
available, the year in which the landfill last received waste.
* * * * *
    37. Section 98.464 is amended by:
    a. Revising paragraph (b) introductory text.
    b. Revising paragraph (b)(1).
    c. Revising paragraph (b)(3).
    d. In paragraph (b)(4), revising the first sentence, redesignating 
Equation TT-8 as Equation TT-7, and revising the definition of ``% 
Volatile Solidsx'' and ``% Total Solidsx''.
    e. Redesignating paragraphs (c), (d),(e) and (f) as paragraphs (d), 
(e), and (f) and (h) respectively.
    f. Adding paragraph (c).
    g. Adding paragraph (g).

Sec.  98.464  Monitoring and QA/QC requirements.

* * * * *
    (b) For each waste stream received during the reporting year for 
which you choose to determine volatile solids concentration for the 
purposes of Sec.  98.460(c)(2)(xii) or choose to determine a landfill-
specific DOCx for use in Equation TT-1 of this subpart, you 
must collect and test a representative sample of that waste stream 
using the methods specified in paragraphs (b)(1) through (b)(4) of this 
section.
    (1) Develop and follow a sampling plan to collect a representative 
sample of each waste stream (as received at the landfill) for which 
testing is elected.
* * * * *
    (3) For the purposes of Sec.  98.460(c)(2)(xii), the volatile 
solids concentration (weight percent on a dry basis) is the percent 
volatile solids determined using Standard Method 2540G ``Total, Fixed, 
and Volatile Solids in Solid and Semisolid Samples'' (incorporated by 
reference; see Sec.  98.7).
    (4) Calculate the waste stream-specific DOCx value using 
Equation TT-7 of this section.
[GRAPHIC] [TIFF OMITTED] TP04AU11.044

* * * * *
% Volatile Solidsx = Percent volatile solids determined 
using Standard Method 2540G ``Total, Fixed, and Volatile Solids in 
Solid and Semisolid Samples'' (incorporated by reference; see Sec.  
98.7) for Year X [milligrams (mg) volatile solids per 100 mg dried 
solids].
% Total Solidsx = Percent total solids determined using 
Standard Method 2540G ``Total, Fixed, and Volatile Solids in Solid 
and Semisolid Samples'' (incorporated by reference; see Sec.  98.7) 
for Year X (mg dried solids per 100 mg wet waste).

    (c) For each waste stream for which you choose to determine 
volatile solids concentration for the purposes of paragraph Sec.  
98.460(c)(2)(xii), and that was historically managed in the landfill 
but was not received during the first reporting year, you must 
determine volatile solids concentration of the waste stream as 
initially placed in the landfill using the methods specified in 
paragraph (c)(1) or (c)(2) of this section, as applicable.
    (1) If you can identify a similar waste stream to the waste stream 
that was historically managed in the landfill, you must determine the 
volatile solids concentration of the similar waste stream using the 
procedures in paragraphs (b)(1) through (b)(3) of this section.
    (2) If you cannot identify a similar waste stream to the waste 
stream that was historically managed in the landfill, you may determine 
the volatile solids concentration of the historically managed waste 
stream using process knowledge. You must document the basis for 
volatile solids concentration as determined through process knowledge.
    (d) For landfills with gas collection systems, operate, maintain, 
and calibrate a gas composition monitor capable of measuring the 
concentration of CH4 according to the requirements specified 
at Sec.  98.344(b).
    (e) For landfills with gas collection systems, install, operate, 
maintain, and calibrate a gas flow meter capable of measuring the 
volumetric flow rate of the recovered landfill gas according to the 
requirements specified at Sec.  98.344(c).
    (f) For landfills with gas collection systems, all temperature, 
pressure, and if applicable, moisture content monitors must be 
calibrated using the procedures and frequencies specified by the 
manufacturer.
    (g) For landfills electing to measure the fraction by volume of 
CH4 in landfill gas (F), follow the requirements in 
paragraphs (g)(1) and (g)(2) of this section.
    (1) Use a gas composition monitor capable of measuring the 
concentration of CH4 on a dry basis that is properly 
operated, calibrated, and maintained according to the requirements 
specified at Sec.  98.344(b). You must either use a gas composition 
monitor that is also capable of measuring the O2 
concentration correcting for excess (infiltration) air or you must 
operate, maintain, and calibrate a second monitor capable of measuring 
the O2 concentration on a dry basis according to the 
manufacturer's specifications.
    (2) Use Equation TT-8 of this section to correct the measured 
CH4 concentration to 0% oxygen. If multiple CH4 
concentration measurements are made during the reporting year, 
determine F separately for each

[[Page 47420]]

measurement made during the reporting year, and use the results to 
determine the arithmetic average value of F for use in Equation TT-1 of 
this part.
[GRAPHIC] [TIFF OMITTED] TP04AU11.045

Where:

F = Fraction by volume of CH4 in landfill gas (fraction, 
dry basis, corrected to 0% oxygen).
CCH4 = Measured CH4 concentration in landfill 
gas (volume %, dry basis).
20.9c = Defined O2 correction basis, (volume 
%, dry basis).
20.9 = O2 concentration in air (volume %, dry basis).
%O2 = Measured O2 concentration in landfill 
gas (volume %, dry basis).

    (h) The facility shall document the procedures used to ensure the 
accuracy of the estimates of disposal quantities and, if the industrial 
waste landfill has a gas collection system, gas flow rate, gas 
composition, temperature, pressure, and moisture content measurements. 
These procedures include, but are not limited to, calibration of 
weighing equipment, fuel flow meters, and other measurement devices. 
The estimated accuracy of measurements made with these devices shall 
also be recorded, and the technical basis for these estimates shall be 
provided.
    38. Section 98.466 is amended by:
    a. Revising paragraph (b) introductory text.
    b. Revising paragraph (b)(2).
    c. Adding paragraphs (b)(3) and (b)(4).
    d. Revising paragraph (c)(3)(ii).
    e. Revising paragraph (d).
    f. Revising paragraph (f).
    g. Revising paragraph (g)(1).

Sec.  98.466  Data reporting requirements.

* * * * *
    (b) Report the following waste characterization and modeling 
information:
* * * * *
    (2) A description of each waste stream (including the types of 
materials in each waste stream) for which Equation TT-1 of this subpart 
is used to calculate modeled CH4 generation.
    (3) The fraction of CH4 in the landfill gas, F, (volume 
fraction, dry basis, corrected to 0% oxygen) for the reporting year and 
an indication as to whether this was the default value or a value 
determined through measurement data.
    (4) The methane correction factor (MCF) value used in the 
calculations. If an MCF value other than the default of 1 is used, 
provide a description of the aeration system, including aeration blower 
capacity, the fraction of the landfill containing waste affected by the 
aeration, the total number of hours during the year the aeration blower 
was operated, and other factors used as a basis for the selected MCF 
value.
    (c) * * *
    (3) * * *
    (ii) The year, the waste disposal quantity and production quantity 
for each year used in Equation TT-2 of this subpart to calculate the 
average waste disposal factor (WDF).
* * * * *
    (d) For each year of landfilling starting with the ``Start Year'' 
(S) and each year thereafter up to the current reporting year, report 
the following information:
    (1) The calendar year for which the following data elements apply.
    (2) The quantity of waste (Wx) disposed of in the 
landfill (metric tons, wet weight) for the specified year for each 
waste stream identified in paragraph (b) of this section.
    (3) The degradable organic carbon (DOCx) value (mass 
fraction) for the specified year and an indication as to whether this 
was the default value from Table TT-1 of this subpart or a value 
determined through sampling and calculation for each waste stream 
identified in paragraph (b) of this section.
* * * * *
    (f) The modeled annual methane generation (GCH4) for the 
reporting year (metric tons CH4) calculated using Equation 
TT-1 of this subpart.
    (g) * * *
    (1) The annual methane emissions (i.e., the methane generation 
(MG), adjusted for oxidation, calculated using Equation TT-6 of this 
subpart), reported in metric tons CH4.
* * * * *
    39. Section 98.467 is revised to read as follows:

Sec.  98.467  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must 
retain the calibration records for all monitoring equipment, including 
the method or manufacturer's specification used for calibration, and 
all total and volatile solids concentration measurement data used for 
the purposes of paragraph Sec.  98.460(c)(2)(xii) or used to determine 
landfill-specific DOCx values.
    40. Section 98.468 is amended by adding the definitions for 
``Construction and demolition (C&D) waste landfill'' and ``Design 
capacity'' to read as follows:

Sec.  98.468  Definitions.

* * * * *
    Construction and demolition (C&D) waste landfill means a solid 
waste disposal facility subject to the requirements of subparts A or B 
of part 257 of this chapter that receives construction and demolition 
waste and does not receive hazardous waste (defined in Sec.  261.3 of 
this chapter) or industrial solid waste (defined in Sec.  258.2 of this 
chapter) or municipal solid waste (defined in Sec.  98.6 of this part) 
other than residential lead-based paint waste. A C&D waste landfill 
typically receives any one or more of the following types of solid 
wastes: roadwork material, excavated material, demolition waste, 
construction/renovation waste, and site clearance waste.
    Design capacity means the maximum amount of solid waste a landfill 
can accept, as indicated in terms of volume or mass in the most recent 
permit issued by the State, local, or Tribal agency responsible for 
regulating the landfill, plus any in-place waste not accounted for in 
the most recent permit. If the owner or operator chooses to convert the 
design capacity from volume to mass to determine its design capacity, 
the calculation must include a site specific density, which must be 
recalculated annually.
* * * * *
    41. Table TT-1 of Subpart TT is amended by revising the entries for 
``Construction and Demolition'' and ``Inert Waste [i.e., wastes listed 
in Sec.  98.460(c)(2)]'' to read as follows:

[[Page 47421]]

           Table TT-1 of Subpart TT--Default DOC and Decay Rate Values for Industrial Waste Landfills
----------------------------------------------------------------------------------------------------------------
                                                                  DOC                        k
                                                                (weight      K  [dry     [moderate     k  [wet
                     Industry/waste type                       fraction,     climate      climate      climate
                                                               wet basis)  \a\] (yr-1)  \a\] (yr-1)  \a\] (yr-1)
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
Construction and Demolition.................................         0.08         0.02         0.03         0.04
Inert Waste [i.e., wastes listed in Sec.   98.460(c)(2)]....            0            0            0            0
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------
\a\ The applicable climate classification is determined based on the annual rainfall plus the recirculated
  leachate application rate. Recirculated leachate application rate (in inches/year) is the total volume of
  leachate recirculated from company records or engineering estimates and applied to the landfill divided by the
  area of the portion of the landfill containing waste [with appropriate unit conversions].
(1) Dry climate = precipitation plus recirculated leachate less than 20 inches/year.
(2) Moderate climate = precipitation plus recirculated leachate from 20 to 40 inches/year (inclusive).
(3) Wet climate = precipitation plus recirculated leachate greater than 40 inches/year.
Alternatively, landfills that use leachate recirculation can elect to use the k value for wet climate rather
  than calculating the recirculated leachate rate.

[FR Doc. 2011-18712 Filed 8-3-11; 8:45 am]
BILLING CODE 6560-50-P