[Federal Register Volume 76, Number 175 (Friday, September 9, 2011)]
[Proposed Rules]
[Pages 56010-56051]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2011-21725]



[[Page 56009]]

Vol. 76

Friday,

No. 175

September 9, 2011

Part II





Environmental Protection Agency





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40 CFR Part 98





Mandatory Reporting of Greenhouse Gases: Technical Revisions to the 
Electronics Manufacturing and the Petroleum and Natural Gas Systems 
Categories of the Greenhouse Gas Reporting Rule; Proposed Rule

  Federal Register / Vol. 76 , No. 175 / Friday, September 9, 2011 / 
Proposed Rules  

[[Page 56010]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 98

[EPA-HQ-OAR-2011-0512; FRL-9456-4]
RIN 2060-AR09


Mandatory Reporting of Greenhouse Gases: Technical Revisions to 
the Electronics Manufacturing and the Petroleum and Natural Gas Systems 
Categories of the Greenhouse Gas Reporting Rule

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: This action proposes technical revisions to the electronics 
manufacturing and the petroleum and natural gas systems source 
categories of the greenhouse gas reporting rule. Proposed changes 
include providing clarification on existing requirements, increasing 
flexibility for certain calculation methods, amending data reporting 
requirements clarifying terms and definitions, and technical 
corrections. In addition, the Environmental Protection Agency is 
proposing to amend the definition of heat transfer fluids in subpart I 
to include more fluorocarbons used as heat transfer fluids in the 
electronics manufacturing industry.

DATES: Comments. Comments must be received on or before October 11, 
2011, unless a public hearing is held, in which case comments must be 
received on or before October 24, 2011.
    Public Hearing. A public hearing will be held if requested. To 
request a hearing, please contact the person listed in the following 
FOR FURTHER INFORMATION CONTACT section by September 16, 2011. If 
requested, the hearing will be conducted on September 26, 2011, in the 
Washington, DC area. EPA will publish further information about the 
hearing in the Federal Register if a hearing is requested.

ADDRESSES: You may submit your comments, identified by Docket ID No. 
EPA-HQ-OAR-2011-0512 by any of the following methods:
     Federal eRulemaking Portal: http://www.regulations.gov. 
Follow the online instructions for submitting comments.
    E-mail: [email protected]. 
Include Docket ID No. EPA-HQ-OAR-2011-0512 in the subject line of the 
message.
     Fax: (202) 566-9744.
     Mail: Environmental Protection Agency, EPA Docket Center 
(EPA/DC), Mail Code 28221T, Attention Docket ID No. EPA-HQ-OAR-2011-
0512, 1200 Pennsylvania Avenue, NW., Washington, DC 20460.
     Hand/Courier Delivery: EPA Docket Center, Public Reading 
Room, EPA West Building, Room 3334, Attention Docket ID No. EPA-HQ-OAR-
2011-0512, 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-
2011-0512, Mandatory Reporting of Greenhouse Gases: Petroleum and 
Natural Gas Systems. 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 for viewing at the 
EPA Docket Center. Publicly available docket materials are available 
either electronically in http://www.regulations.gov or in hard copy at 
the EPA Docket Center, 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: 
[email protected]. For technical questions, please see the 
Greenhouse Gas Reporting 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 public hearing, 
please go to http://www.epa.gov/climatechange/emissions/ghgrulemaking.html. Alternatively, you may contact Carole Cook at 202-
343-9263.

SUPPLEMENTARY INFORMATION:
    Worldwide Web (WWW). In addition to being available in the docket, 
an electronic copy of today's 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 rule Web site at 
http://www.epa.gov/climatechange/emissions/ghgrulemaking.html.
    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: 
[email protected].
    Regulated Entities. The Administrator determined that this action 
is subject to the provisions of Clean Air Act (CAA) section 307(d). If 
finalized, these amended regulations could affect owners or operators 
of petroleum and natural gas systems and certain electronic 
manufacturers. Regulated categories and entities may include those 
listed in Table 1 of this preamble:

[[Page 56011]]



                               Table 1--Examples of Affected Entities by Category
----------------------------------------------------------------------------------------------------------------
                Source category                      NAICS               Examples of affected 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.
Electronics Manufacturing.....................          334111  Microcomputers manufacturing facilities.
                                                        334413  Semiconductor, photovoltaic (solid-state) device
                                                                 manufacturing facilities.
                                                        334419  Liquid Crystal Display (LCD) unit screens
                                                                 manufacturing facilities.
                                                        334419  Micro-electro-mechanical systems (MEMS)
                                                                 manufacturing facilities.
----------------------------------------------------------------------------------------------------------------

    Table 1 of this preamble is not intended to be exhaustive, but 
rather provides a guide for readers regarding facilities likely to be 
affected by this action. Although Table 1 of this preamble lists the 
types of facilities of which EPA is aware that could be potentially 
affected by this action, other types of facilities not listed in the 
table could also be affected. To determine whether you are affected by 
this action, you should carefully examine the applicability criteria 
found in 40 CFR part 98 subpart A, 40 CFR part 98 subpart I and 40 CFR 
part 98 subpart W. If you have questions regarding the applicability of 
this action to a particular facility, 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.

AGA American Gas Association
API American Petroleum Institute
AXPC American Exploration and Production Council
BAMM Best Available Monitoring Methods
BOEMRE Bureau of Ocean Energy Management, Regulation and Enforcement
CAA Clean Air Act
CBI confidential business information
CEC Chesapeake Energy Corporation
CEMS continuous emission monitoring systems
cfd cubic feet per day
CFR Code of Federal Regulations
CH4 methane
CO2 carbon dioxide
CO2e CO2-equivalent
COR certificate of representation
e-GGRT electronic greenhouse gas reporting tool
EIA Economic Impact Analysis
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
FCML Field Code Master List
FERC Federal Energy Regulatory Commission
FR Federal Register
GHG greenhouse gas
GPA Gas Processors Association
GOR gas to oil ratio
GRI Gas Research Institute
Hp horsepower
GWP global warming potential
HHV high heat value
HTF heat transfer fluid
IBR incorporation by reference
ICR information collection request
LDC Local Distribution Company
ISO International Organization for Standardization
kg kilograms
LDCs local natural gas distribution companies
LNG liquefied natural gas
M&R meters and regulators
mmBtu million British thermal units
mmHg millimeters of Mercury
MMscfd million standard cubic feet per day
mTCO2e million metric tons carbon dioxide equivalent
MRR mandatory GHG reporting rule
N2O nitrous oxide
NAICS North American Industry Classification System
NF3 nitrogen trifluoride
NGLs natural gas liquids
NPS nominal pipe size
NTTAA National Technology Transfer and Advancement Act
OAQPS Office of Air Quality, Planning and Standards
OMB Office of Management and Budget
PHMSA Pipeline and Hazardous Material Safety Administration
QA/QC quality assurance/quality control
RFA Regulatory Flexibility Act
SBA Small Business Administration
SBREFA Small Business Regulatory Enforcement and Fairness Act
SF6 sulfur hexafluoride
T-D Transmission Distribution
TSD technical support document
U.S. United States
UMRA Unfunded Mandates Reform Act of 1995
USC United States Code

Table of Contents

I. Background
    A. How is this preamble organized?
    B. Background on the Proposed 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 I--Electronics Manufacturing
    C. Subpart W--Petroleum and Natural Gas Systems
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

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 
legal authority under the CAA to collect data on GHGs.
    The second section of this preamble describes in detail the changes 
that are being proposed to correct technical errors or 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 discusses the various statutory 
and executive order requirements applicable to this proposed 
rulemaking.

B. Background on the Proposed Action

    EPA published subpart I: Electronics Manufacturing of the 
Greenhouse Gas Reporting Program (GHGRP) on December 1, 2010 (75 FR 
74774) subpart I of the GHGRP requires monitoring and reporting of GHG 
emissions from electronics manufacturing. Electronics manufacturing 
facilities covered by subpart I are those that have emissions equal to 
or greater than 25,000 mtCO2e.
    Following the publication of subpart I in the Federal Register, 3M 
Company

[[Page 56012]]

(3M) sought reconsideration of the final rule requirements for 
reporting fluorinated heat transfer fluids (HTFs). In this action EPA, 
is proposing amendments to the provisions in subpart I related to 
calculating and reporting fluorinated HTFs to reflect the Agency's 
intent to cover all fluorocarbons (except for ozone depleting 
substances regulated under EPA's Stratospheric Protection Regulations 
at 40 CFR part 82) that can enter the atmosphere under the conditions 
in which HTFs are used in the electronics manufacturing industry.
    EPA published Subpart W: Petroleum and Natural Gas Systems of the 
Greenhouse Gas Reporting Rule on November 30, 2010(75 FR 74458). 
Subpart W of the GHGRP, which applies to facilities in specific 
segments of the petroleum and natural gas industry that emit GHGs 
greater than or equal to 25,000 mtCO2e per year, covers 
approximately 85 percent of GHG emissions--including vented, equipment 
leak, and combustion emissions--from facilities in specific segments of 
the petroleum and natural gas industry.
    Following the publication of subpart W in the Federal Register, 
several industry groups requested reconsideration of several provisions 
in the final rule. Part of the proposed amendments in this action are 
in response to those requests for reconsideration. Today we are 
granting reconsideration of, and requesting comment on, those issues 
raised in the petitions listed in Table 2 where indicated in such Table 
that the issue is addressed in this action. While we do not necessarily 
agree that each of those identified issues meet the criteria for 
reconsideration, we nonetheless believe that they do raise important 
implementation issues and are thus granting reconsideration of those 
issues and proposing concomitant revisions to the rule. At this time we 
are not granting reconsideration of other issues raised in those 
petitions where indicated in the following table that they are not 
being addressed in this action but will consider those issues at a 
later time.

                 Table 2--Petitions for Reconsideration
------------------------------------------------------------------------
                                                        Is this issue
   Petitioner and date of       Issue raised for      addressed in this
           letter                reconsideration           action?
------------------------------------------------------------------------
American Gas Association by   Non custody transfer  Yes.
 letter dated March 2, 2011.   city gate station
                               terminology. AGA
                               asserted that
                               ``[s]everal
                               provisions in the
                               Subpart W rule and
                               preamble seem to
                               imply that a `non-
                               custody-transfer
                               city gate station'
                               will always have a
                               meter''.
                             -------------------------------------------
                              Custody transfer      Yes.
                               city gate station
                               terminology. AGA
                               asserted that the
                               term ``custody
                               transfer city gate
                               station'' in
                               subpart W was
                               unclear and needed
                               clarification.
                             -------------------------------------------
                              Use of GTI emission   Partially.
                               factors. AGA
                               requested
                               reconsideration of
                               the emissions
                               factors for Local
                               Distribution
                               Companies in the
                               final rule.
                             -------------------------------------------
                              New emission factor   Yes.
                               formulas are
                               confusing or
                               contain math errors
                               that vastly inflate
                               emission estimates.
                               AGA asserted that
                               the ``[t]he new
                               emissions factor
                               equations W-30, W-
                               31 and W-32 in the
                               final rule are
                               confusing. Since
                               these formulas were
                               not included in the
                               proposed rule, AGA
                               did not have an
                               opportunity to
                               comment on them''.
                             -------------------------------------------
                              New electronic        No. This is being
                               reporting form is     addressed in a
                               not yet available     separate package.
                               for comment or
                               testing. AGA
                               asserted that
                               ``[s]takeholders
                               should be given the
                               opportunity to
                               comment and to have
                               access to the
                               reporting software
                               to perform trial
                               runs.
                             -------------------------------------------
                              EPA should exclude    Yes.
                               small internal
                               combustion sources,
                               not just external
                               combustion. AGA
                               asserted that ``EPA
                               should revise the
                               final rule to
                               provide a de
                               minimis exemption
                               for small internal
                               and external
                               combustion sources
                               at underground
                               storage
                               facilities.'' Also
                               ``AGA request
                               reconsideration of
                               this new exclusion
                               for small
                               combustion sources
                               and revision to
                               include both small
                               internal and
                               external combustion
                               sources * * *''.
                             -------------------------------------------
                              AGA asserted that     No.
                               ``[t]he rule
                               contains
                               conflicting
                               provisions
                               regarding whether
                               emissions from
                               dehydrator units at
                               underground storage
                               facilities should
                               or should not be
                               reported''.
                             -------------------------------------------

[[Page 56013]]

 
                              AGA asserted that     Yes.
                               ``EPA did not
                               provide rational
                               explanation for
                               using outdated
                               inaccurate emission
                               factors rather than
                               modern updated
                               emission factors''.
                             -------------------------------------------
                              AGA asserted that     No.
                               ``[d]efinition of
                               `facility' is
                               overbroad and
                               confusing.'' The
                               facility definition
                               referred to here is
                               found in 40 CFR
                               98.238.
                             -------------------------------------------
                              AGA asserted that     No.
                               ``It was arbitrary
                               and capricious for
                               EPA to create a
                               subpart W reporting
                               regulation for a
                               null set--LNG
                               storage facilities
                               will not exceed the
                               25,000 ton per year
                               threshold''.
                             -------------------------------------------
                              AGA asserted that     No.
                               ``It was arbitrary
                               and capricious for
                               EPA to create a
                               subpart W reporting
                               regulation for LNG
                               import and export
                               facilities--which
                               have only minimal
                               methane leaks''.
------------------------------------------------------------------------
Chesapeake Energy/American    Measurement of        No.
 Exploration and Production    Emissions. CEC/AXPC
 Council by Letter Dated       asserted that ``EPA
 January 31, 2011.             proposed to require
                               costly measurement
                               and reporting of
                               emissions from
                               hundreds of
                               thousands of
                               sources. Commenters
                               asked EPA to adopt
                               a reasonable
                               threshold for
                               measurement, so
                               that emissions
                               could still be
                               accounted for, but
                               in a cost-effective
                               way. Commenters
                               recommended using
                               the API Compendium
                               for that purpose''.
                             -------------------------------------------
                              De minimis emissions  Yes.
                               from portable
                               equipment. CEC/AXPC
                               asserted that
                               ``[t]he final rule
                               likewise fails to
                               adequately support
                               requiring the
                               reporting of de
                               minimis emissions
                               from portable
                               equipment as EPA
                               proposedEPA asserts
                               a truism that all
                               emissions
                               contribute to
                               sector emissions
                               overall''.
                             -------------------------------------------
                              Designated            Yes.
                               Representative. CEC/
                               AXPC requested
                               reconsideration of
                               the designated
                               representative
                               provisions in the
                               final rule.
                             -------------------------------------------
                              Dump Valves. CEC/     No.
                               AXPC asserts that
                               ``[t]he requirement
                               to measure and
                               report emissions
                               from dump valves
                               associated with
                               onshore production
                               storage tanks * * *
                               is a new and
                               unreasonable
                               ongoing monitoring
                               and record keeping
                               burden * * *''.
                             -------------------------------------------
                              Best Available        No. This is being
                               Monitoring Methods.   addressed in a
                                                     separate action (76
                                                     FR 37300).
                             -------------------------------------------
                              Emissions Manifolded  No.
                               to Common Vents.
                               CEC/AXPC asserted
                               that the final
                               provisions for
                               centrifugal
                               compressor
                               monitoring ``[n]ot
                               only expands the
                               rule to cover
                               equipment that was
                               not identified in
                               the proposed rule,
                               but it is also
                               inconsistent and
                               creates ambiguity
                               for covered sources
                               regarding what is
                               required''.
                             -------------------------------------------
                              Compressor            No.
                               Monitoring. CEC/
                               AXPC asserts that
                               ``[t]he final rule
                               imposes a new
                               obligation to
                               monitor and report
                               that would require
                               major piping
                               modifications and
                               that would unduly
                               threaten worker
                               safety''.
                             -------------------------------------------

[[Page 56014]]

 
                              Excluding Boosting    Yes.
                               Stations. CEC/AXPC
                               asserted that
                               ``[t]he final rule
                               fails to
                               distinguish between
                               a boosting station,
                               which is exempt,
                               and an `onshore
                               natural gas
                               transmission
                               compression
                               facility' which
                               must report under
                               the rule''.
                             -------------------------------------------
                              Onshore Natural Gas   Yes.
                               Transmission
                               Compression
                               Industry Segment
                               Definition. CEC/
                               AXPC asserted that
                               ``[a]s presently
                               drafted, the
                               unclear and
                               inconsistent final
                               provisions render
                               the rule arbitrary
                               and capricious and
                               contrary to law.''
                               And ``The term
                               `onshore natural
                               gas transmission
                               compression' means
                               a stationary
                               combination of
                               compressors that
                               move natural gas at
                               elevated pressure
                               from production
                               fields or natural
                               gas processing
                               facilities in
                               transmission
                               pipelines or into
                               storage. 40 CFR
                               Sec.
                               98.230(a)(4). A
                               transmission
                               compressor station
                               can include
                               equipment to
                               separate liquids or
                               dehydrate natural
                               gas Id. However,
                               according to the
                               final rule this
                               source category
                               does not include
                               gathering lines and
                               boosting stations''.
                             -------------------------------------------
                              Onshore Natural Gas   Yes.
                               Processing Industry
                               Segment Definition.
                               CEC/AXPC asserted
                               that ``[a]s
                               presently drafted,
                               the unclear and
                               inconsistent final
                               provisions render
                               the rule arbitrary
                               and capricious and
                               contrary to law.''
                               CEC/AXPC further
                               stated concerns
                               with the definition
                               for onshore natural
                               gas processing
                               industry segment
                               definition and
                               where the segment
                               differs from
                               onshore natural gas
                               transmission
                               industry segment,
                               and from gathering
                               lines and boosting
                               stations.
                             -------------------------------------------
                              Gathering Lines and   Yes.
                               Boosting Stations.
                               CEC/AXPC asserted
                               that ``EPA noted
                               that the `final
                               rule does not
                               require reporting
                               of emissions from
                               [the] gathering and
                               boosting segment of
                               the industry.'
                               Thisis not helpful
                               and gives industry
                               no clarity
                               regarding which
                               compressor stations
                               are required to
                               report''.
                             -------------------------------------------
                              Mapping Wells to      Yes.
                               Fields. CEC/AXPC
                               asserted that ``EPA
                               has not clarified
                               how reporting
                               entities are
                               supposed to map
                               wells to a
                               particular `field.'
                               '' Also, CEC/AXPC
                               asserted that
                               ``[w]ithout
                               sufficient clarity
                               regarding what
                               wells are in a
                               particular field,
                               it is difficult for
                               covered sources to
                               know with certainty
                               what gas
                               composition is
                               considered
                               representative for
                               each well''.
                             -------------------------------------------
                              Definition of         No.
                               Facility for
                               Onshore Petroleum
                               and Natural Gas
                               Production. CEC/
                               AXPC asserted that
                               the ``EPA has not
                               provided a reasoned
                               explanation for why
                               a term other than
                               `facility' cannot
                               be adopted for
                               Subpart w (such as
                               `Reporting Area')
                               in order to avoid
                               unintended
                               confusion and
                               inaccuracies in
                               reporting''.
                             -------------------------------------------
                              Pipeline Quality      Yes.
                               Natural Gas. CEC/
                               AXPC asserted that
                               ``[t]here is not a
                               clear and
                               unambiguous
                               definition in the
                               final rule for
                               `pipeline quality'
                               natural gas''.
                             -------------------------------------------

[[Page 56015]]

 
                              Producing Horizon/    Yes.
                               formation
                               definition. CEC/
                               AXPC asserted that
                               ``[t]here is not a
                               clear and
                               unambiguous
                               definition provided
                               in the final rule
                               for the term
                               `producing horizon/
                               formation' ''.
                             -------------------------------------------
                              Well testing venting  Yes.
                               and flaring
                               clarification. CEC/
                               AXPC asserted that
                               ``[t]he final rule
                               is unclear
                               regarding the
                               requirement to
                               report emissions
                               from well testing
                               venting and
                               flaring''.
                             -------------------------------------------
                              Associated Gas        No.
                               Venting and
                               Flaring. CEC/AXPC
                               asserted that ``40
                               CFR 98.233(m)
                               imposes a
                               requirement to
                               report emissions
                               from associated gas
                               venting and flaring
                               not in conjunction
                               with well testing.
                               While this
                               regulation
                               references 40 CFR
                               98.233(l), that
                               definition is
                               unclear. Therefore
                               industry is left
                               without clarity
                               regarding what
                               emissions are
                               included in
                               `associated gas
                               venting and flaring
                               not in conjunction
                               with well testing'
                               ''.
                             -------------------------------------------
                              Pneumatic Devices.    Yes.
                               CEC/AXPC asserted
                               that ``EPA has not
                               given sufficient
                               consideration to
                               the burden imposed
                               by requiring that
                               the bleed rate of
                               each device be
                               determined in order
                               to count and
                               classify the
                               devices''.
                             -------------------------------------------
                              Blowdown Vent         Yes.
                               Stacks. CEC/AXPC
                               asserted that
                               ``[t]he sources
                               that are required
                               to report emissions
                               from blowdown vent
                               stacks are not
                               clear''.
------------------------------------------------------------------------
American Petroleum Institute  Best Available        No. This is being
 by Letter Dated January 31,   Monitoring Methods.   addressed in a
 2011.                                               separate action (76
                                                     FR 37300).
                             -------------------------------------------
                              Exclusion for         Yes.
                               `small' internal
                               combustion sources
                               is needed. API
                               asserted that ``EPA
                               should extend the
                               exclusion for small
                               external combustion
                               sources to small
                               internal combustion
                               sources''.
                             -------------------------------------------
                              Stuck dump valves to  No.
                               separators/tanks in
                               onshore production
                               operations. API
                               asserted that
                               ``[t]he new
                               requirement to
                               report emissions
                               from stuck dump
                               valves requires
                               reporters to check
                               all dump valves on
                               a well site * * *
                               These requirements
                               represent an
                               administrative
                               burden for reports
                               that was not
                               contemplated in the
                               proposed rule''.
                             -------------------------------------------
                              Reporting             No.
                               requirements for
                               centrifugal and
                               reciprocating
                               compressor venting
                               at onshore natural
                               gas processing
                               facilities. API
                               requested EPA to
                               reconsider an
                               asserted expansion
                               of reporting
                               requirements for
                               centrifugal and
                               reciprocating
                               compressor venting
                               at onshore natural
                               gas processing
                               facilities.
                             -------------------------------------------

[[Page 56016]]

 
                              Requirements for      Yes.
                               flare stack
                               emission associated
                               with onshore oil
                               and gas production.
                               API asserted that
                               ``[e]missions from
                               flare stacks
                               associated with
                               onshore oil and gas
                               production were not
                               included in the
                               Petroleum and
                               Natural Gas
                               production industry
                               segment in the
                               proposed rule * * *
                               the inclusion of
                               emissions from
                               flare stacks
                               associated with
                               onshore oil and gas
                               production is
                               duplicative,
                               burdensome, and a
                               potential source of
                               reporting
                               inaccuracies''.
                             -------------------------------------------
                              Reporting             No.
                               requirements for
                               all venting and
                               flaring activities
                               in the production
                               source category.
                               API asserts that
                               ``EPA's expansion
                               of the reporting
                               obligations in
                               98.233(m) to
                               include upset or
                               maintenance gas
                               from producing
                               wells imposes
                               additional and
                               extensive burdens
                               on regulated
                               parties which was
                               not included in the
                               proposal''.
                             -------------------------------------------
                              Use of gas            Yes.
                               composition based
                               on available sample
                               analysis for
                               reporters without
                               continuous gas
                               composition
                               analyzer. API
                               asserts that ``EPA
                               should resolve the
                               ambiguity created
                               by the current
                               language''.
                             -------------------------------------------
                              Portable combustion   Yes.
                               equipment that
                               cannot move on
                               roadways under its
                               own power and drive
                               train that is
                               stationed at a
                               wellhead for less
                               than 30 days in a
                               reporting year. API
                               asserts that
                               ``[t]he final rule
                               requires reporters
                               to account for this
                               equipment, despite
                               the fact that it is
                               on site for an
                               extremely short
                               period of time * *
                               * it is unrealistic
                               to expect reporters
                               to measure
                               emissions from
                               every piece of
                               portable combustion
                               equipment that is
                               only onsite for a
                               matter of days''.
                             -------------------------------------------
                              Separate              Yes.
                               calculations for
                               subsonic and
                               supersonic flow
                               when both happen
                               during a single
                               completion. API
                               asserted that
                               ``[t]he proposed
                               rule did not
                               include a
                               requirement that
                               well completions
                               have separate
                               calculations for
                               subsonic and
                               supersonic flow
                               when both occur
                               during a single
                               completion. The
                               final rule adds
                               this requirement,
                               which is not
                               technically
                               possible''.
                             -------------------------------------------
                              Flow meter            Yes.
                               requirements. API
                               asserts that
                               ``[t]he final rule
                               adds a requirement
                               at 40 CFR 98.234(b)
                               that all flow
                               meters, composition
                               analyzers and
                               pressure gauges be
                               operated and
                               calibrated
                               according to the
                               procedures in
                               Section 98.3(i) of
                               the MRR * * * API
                               is concerned about
                               the potential
                               unintended
                               consequence
                               following the
                               addition of
                               stationary source
                               combustion
                               equipment at a well
                               pad at new 40 CFR
                               98.232(C)(22),
                               which required
                               compliance with 40
                               CFR
                               98.233(z)(2)(1)''.
                             -------------------------------------------

[[Page 56017]]

 
                              Emission factors for  Yes.
                               continuous high-
                               bleed, continuous
                               low-bleed, and
                               intermittent bleed
                               pneumatic devices.
                               API asserted that
                               ``[a]lthough EPA
                               has provided
                               emission factors in
                               Table W-1A that
                               apply to continuous
                               high-bleed,
                               continuous low-
                               bleed, and
                               intermittent bleed
                               pneumatic devices,
                               EPA has not
                               provided guidance
                               on how to classify
                               pneumatic devices
                               according to these
                               three categories''.
                             -------------------------------------------
                              Definitions to        Yes.
                               Industry
                               Categories. API
                               asserted that the
                               ``[a]ltered final
                               rule creates
                               ambiguity as to
                               whether certain
                               facilities are
                               included in the
                               production
                               category, excluded
                               as gathering or
                               booster stations,
                               or included under
                               the gas processing
                               category''.
                             -------------------------------------------
                              Number of plunger     Yes.
                               lifts and average
                               casing diameter in
                               inches. API
                               asserted that
                               ``[t]he final rule
                               adds 40 CFR
                               98.236(c)(5)
                               requirements to
                               report the number
                               of plunger lifts
                               and average casing
                               diameter in inches
                               by field. The
                               difficulty with
                               these additions is
                               not with the
                               requirement for
                               counting plunger
                               lifts and noting
                               casing diameter,
                               but that reporting
                               must take place at
                               the field level''.
                             -------------------------------------------
                              Floating Production   No.
                               Storage and
                               Offloading
                               Equipment. API
                               asserted that
                               ``[t]he proposed
                               rule did not
                               include floating
                               production storage
                               and offloading
                               equipment in the
                               definition of
                               offshore petroleum
                               and natural gas
                               production. API
                               questions the need
                               for this addition
                               at 40 CFR
                               98.230(a)(1)''.
                             -------------------------------------------
                              Basin level           Yes.
                               reporting for
                               onshore petroleum
                               and natural gas
                               production. API
                               asserted that
                               ``[t]his broad
                               definition of
                               onshore production
                               facility is
                               impractical.
                               Subpart W imposes
                               reporting
                               requirements on
                               over 22,000
                               entities operating
                               hundreds of
                               thousands of wells
                               and millions of
                               pieces of equipment
                               scattered over
                               hundreds of
                               thousands of square
                               miles''.
                             -------------------------------------------
                              Field level           Yes.
                               reporting for
                               onshore petroleum
                               and natural gas
                               production. API
                               asserts that
                               ``[t]his level of
                               reporting is
                               problematic when
                               applied to new
                               requirements of the
                               final rule. For the
                               same reasons, it
                               remains problematic
                               when applied to
                               those requirements
                               in the proposed
                               rule that remain in
                               the final rule''.
                             -------------------------------------------
                              Designated            Yes.
                               Representative of
                               Subpart W Facility.
                               API asserted that
                               ``[t]he new basin-
                               level facility
                               definition for
                               onshore petroleum
                               and natural gas
                               production systems
                               adopted in Subpart
                               W adds unreasonable
                               complexity to
                               several of the
                               existing
                               administrative
                               requirements for
                               the designated
                               representative set
                               forth in 40 CFR
                               98.4''.
                             -------------------------------------------

[[Page 56018]]

 
                              Reporting of GHG      Partially.
                               emissions from
                               leased, rented, or
                               contracted
                               activities. API
                               asserts that
                               ``[t]hese
                               requirements create
                               significant
                               complications. A
                               single well pad may
                               be owned by one
                               entity, operated by
                               another entity,
                               lease portable
                               equipment from a
                               third entity, and
                               have that portable
                               equipment operated
                               by yet another
                               entity. The rule
                               places the burden
                               of reporting
                               entirely on the
                               owner of the well
                               or the holders of
                               the operating
                               permit and makes
                               the designated
                               representatives
                               legally responsible
                               for the accuracy of
                               the emissions data
                               provided by third
                               parties''.
                             -------------------------------------------
                              Threshold for         No.
                               ``small'' size
                               units that are
                               exempt from
                               consideration. API
                               asserts that
                               ``[t]he final
                               rule's threshold of
                               0.4 MMscf per day
                               for dehydrator
                               calculations using
                               software and
                               individual
                               reporting is too
                               low''.
------------------------------------------------------------------------
Gas Processors Association    Best Available        No. This is being
 by Letter Dates February      Monitoring Methods.   addressed in a
 11, 2011.                     GPA asserted that     separate action (76
                               ``[s]ubpart W's       FR 37300).
                               best available
                               monitoring method
                               provisions do not
                               provide reporting
                               entities with
                               adequate time to
                               ensure compliance
                               with the final
                               rule''.
                              Compressor venting    No.
                               monitoring
                               requirements. GPA
                               asserted that
                               ``[c]urrent
                               compressor venting
                               monitoring
                               requirements are
                               overly burdensome
                               and present
                               significant safety
                               and operational
                               process concerns to
                               reporting
                               entities''.
                             -------------------------------------------
                              Use of the terms      Yes.
                               ``gathering lines''
                               and ``booster
                               stations'' not
                               being defined in
                               final rule. GPA
                               asserted that
                               ``[t]he terms
                               `gathering lines'
                               and `booster
                               stations' are not
                               defined in the
                               final rule, nor is
                               sufficient detail
                               provided regarding
                               the definition of
                               `gas processing
                               facility.' '' GPA
                               further asserted
                               that ``[a]bsent
                               such definitions
                               and clarifications,
                               there will be
                               substantial
                               confusion as to
                               which facilities
                               are required to
                               report emissions
                               data''.
                             -------------------------------------------
                              Facility definition   No.
                               for onshore
                               petroleum and
                               natural gas
                               production. GPA
                               asserted ``[t]he
                               definition of a
                               facility in Subpart
                               W differs from the
                               definition of a
                               facility provided
                               in all other
                               applicable
                               regulations under
                               the Clean Air Act.
                               This inconsistency
                               will create
                               unnecessary
                               confusion among
                               related programs
                               and is not
                               necessary or
                               justified''.
------------------------------------------------------------------------
Southwest Gas Corporation by  Terms in Subpart W.   Yes.
 Letter Dated January 31,      Southwest Gas
 2011.                         Corporation
                               asserted that
                               ``[t]he USEPA's
                               final rule fails to
                               provide clear
                               definitions that
                               can be used
                               uniformly
                               throughout the
                               natural gas
                               distribution
                               industry''.
                             -------------------------------------------
                              Errors in             Yes.
                               Calculations.
                               Southwest Gas
                               Corporation
                               asserted that the
                               USEPA published
                               errors in equations
                               in 40 CFR 98.233,
                               namely equation W-
                               32.
------------------------------------------------------------------------
Interstate Natural Gas        Best Available        No. This is being
 Association of America.       Monitoring Methods.   addressed in a
                                                     separate action (76
                                                     FR 37300).
------------------------------------------------------------------------

[[Page 56019]]

 
                              Technical Provisions  Partially.
                               in Subpart W. INGAA
                               asserted that
                               ``[n]umerous
                               technical elements
                               of Subpart W remain
                               unclear, confusing,
                               overly complicated
                               or conflicting''.
                             -------------------------------------------
                              INGAA petitioned EPA  Yes.
                               to reconsider the
                               default gas
                               compositions and
                               requested the use
                               of separate default
                               gas compositions
                               for methane and CO2
                               for vented and
                               fugitive emissions
                               for the natural gas
                               transmission
                               compression and
                               storage segments.
                             -------------------------------------------
                              INGAA petitioned EPA  Yes.
                               to reconsider minor
                               clarifications to
                               40 CFR 98.233(t),
                               (u), and (v) for
                               clarity.
                             -------------------------------------------
                              INGAA requested EPA   Yes.
                               to reconsider the
                               provisions in the
                               final rule for
                               determining the
                               type of pneumatic
                               device at a
                               facility. INGAA
                               requested EPA to
                               consider the option
                               of using
                               engineering
                               estimates to
                               determine the type
                               of pneumatic
                               devices.
                             -------------------------------------------
                              INGAA requested EPA   Yes.
                               to reconsider the
                               provisions in the
                               rule related to
                               blowdown vent
                               stacks and
                               requested a
                               reconsideration of
                               those provisions.
                             -------------------------------------------
                              INGAA requested EPA   Yes.
                               to reconsider the
                               provisions in the
                               rule for emissions
                               from blowdown vent
                               stacks and to
                               include an
                               additional equation
                               to allow facilities
                               who currently track
                               emissions by
                               equipment type to
                               submit emission to
                               EPA in that manner.
                             -------------------------------------------
                              INGAA requested that  Yes.
                               EPA to reconsider
                               provisions related
                               to flaring.
                             -------------------------------------------
                              INGAA requested that  No.
                               EPA reconsider
                               provisions for
                               monitoring
                               emissions from
                               centrifugal and
                               reciprocating
                               compressors and to
                               consider including
                               clarifications to
                               rule text.
                             -------------------------------------------
                              INGAA requested EPA   Yes.
                               to reconsider
                               provisions related
                               to monitoring and
                               QA/QC requirements
                               including
                               provisions for the
                               alternative work
                               practice.
                             -------------------------------------------
                              INGAA requested EPA   No.
                               to reconsider
                               missing data
                               provisions and
                               broaden access.
                             -------------------------------------------
                              INGAA requested EPA   Partially.
                               to reconsider
                               provisions as
                               stated in 40 CFR
                               98.236 and
                               requested several
                               clarifications to
                               final text.
------------------------------------------------------------------------

    The proposed amendments in this action include technical 
corrections and clarifications to ensure that the 2010 final rule is 
implemented as intended. Amendments to subparts I and W are also being 
proposed in other actions. Please see 76 FR 47392 (Herein referred to 
as the ``technical corrections rule'') and 76 FR 37300. This proposal 
complements these proposed rules and is not intended to duplicate or 
replace those proposed amendments. In limited cases, an amendment to 
subpart W was proposed in the technical corrections rule and we are 
proposing to amend it further in this action. Additional proposed 
amendments were determined to be necessary to address questions and 
issues raised by stakeholders since development of the proposal of the 
technical corrections rule. Where amendments have been made to the same 
paragraph in this action and in the technical corrections rule, the 
proposal below provides the complete proposed amendatory language for 
how EPA proposes to amend the provision. We are seeking public comment 
only on the issues specifically identified in this proposal for the 
identified subparts. We will not respond to any comments addressing 
other aspects of part 98 or any other related rulemakings.
    EPA promulgated confidentiality determinations for certain data 
elements required to be reported under part 98 and finalized amendments 
to the Special Rules Governing Certain Information Obtained Under the 
Clean

[[Page 56020]]

Air Act, which authorizes EPA to release or withhold as confidential 
reported data according to the confidentiality determinations for such 
data without taking further procedural steps (76 FR 30782, May 26, 2011 
hereinafter referred to as the ``May 26, 2011 Final CBI Rule''). That 
notice addressed reporting of data elements in 34 subparts that were 
determined not to be inputs to emission equations and therefore were 
not proposed to have their reporting deadline deferred. That rule did 
not make confidentiality determinations for eight subparts, including 
subpart W, for which reporting requirements were finalized after 
publication of the July 7, 2010 CBI proposal and July 20, 2010 
supplemental CBI proposal.
    EPA is planning to address the confidentiality determinations for 
the data elements in subpart W in a separate action. EPA plans to issue 
and finalize the confidentiality determinations for subpart W prior to 
the 2012 reporting deadline.

C. Legal Authority

    EPA is proposing these rule amendments under its existing CAA 
authority, specifically authorities provided in section 114 of the CAA.
    As stated in the preamble to the 2009 Final Greenhouse Gas 
Reporting Rule (part 98) (74 FR 56260, October 30, 2009), 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), section 114(a)(1) of the CAA 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 proposed and 2009 final part 981.\1\
---------------------------------------------------------------------------

    \1\ 74 FR 16448 (April 10, 2009) and 74 FR 56260 (October 30, 
2009).
---------------------------------------------------------------------------

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, for subpart W, reporters would be expected to calculate 
emissions and other relevant data for the reports that are submitted in 
2012 using part 98, as amended by this rule, as finalized. We have 
determined that it is feasible for the sources to implement these 
changes for the 2011 reporting year since the proposed revisions 
primarily provide additional clarifications or flexibility regarding 
the existing regulatory requirements, generally do not affect the type 
of information that must be collected, and do not substantially affect 
how emissions are calculated.
    For amendments being proposed today to subpart I, EPA is requesting 
comment on whether to require electronics manufacturing facilities to 
estimate and report 2011 emissions in 2012 for HTFs that would be newly 
included in the scope of subpart I if today's proposed rule amendments 
were finalized.
    For facilities subject to the provisions in 40 CFR part 98--subpart 
W, many proposed revisions simply provide additional information and 
clarity on existing requirements. For instance, we are proposing to 
amend 40 CFR 98.1(c)(1) to clarify that for onshore petroleum and 
natural gas facilities, the references in 40 CFR 98.4 that apply to 
owner(s) and operator(s) refer to the onshore petroleum and natural gas 
production owner or operator, as defined in 40 CFR 98.238. Therefore, 
we are proposing to explicitly make this clarification in 40 CFR 98.1 
(Purpose and Scope). The proposed amendment does not change the burden 
of the 2010 final rule, and in fact, EPA believes that it alleviates 
concerns expressed by industry that the designated representative 
provisions are overly burdensome.
    Some of the proposed amendments for subpart W provide greater 
flexibility or simplified calculation methods for certain facilities. 
For example, we are proposing to amend 40 CFR 98.233(i) to provide an 
additional option to calculate GHG emissions from blowdown vent stacks. 
Specifically, we are proposing to allow reporters the option of 
tracking blowdowns by each occurrence for the same blowdown volume, 
consistent with current practice at some facilities, whereas in the 
final rule, reporters were required to track total blowdown vent 
emissions from all occurrences for the same blowdown volume in a year.
    Further, some proposed amendments for subpart W are to the data 
reporting requirements to provide additional clarity on which GHG 
emissions have to be reported and at which level of aggregation. For 
example, in 40 CFR 98.236 EPA is proposing to clarify where ``vented'' 
emissions should be reported separately from ``flared'' emissions and 
that reporting of CH4, CO2, and N2O 
emissions should be reported individually for each source type in 
CO2e. We have concluded that amendments such as these could 
be implemented for the reports submitted to EPA in 2012 because the 
proposed changes are, with one exception, consistent with the 
calculation methodologies already in part 98 and the owners or 
operators are not required to actually report until March 2012,\2\ 
several months after we expect this proposal to be finalized.
---------------------------------------------------------------------------

    \2\ EPA has proposed to extend the 2012 reporting deadline for 
source categories first required to begin data collection in 2011 
from March 31, 2012 to September 28, 2012. Please see the technical 
corrections rule previously referenced.
---------------------------------------------------------------------------

    The one exception where both the underlying calculation 
requirements and reporting requirements in subpart W are proposed to be 
changed is related to the requirements for field level reporting for 
four emissions sources in the onshore petroleum and natural gas 
production segment. As described further in Section II.C of this 
preamble, we are proposing to amend the calculation and reporting 
requirements for well completions and well workovers, well venting for 
liquids unloading, and storage tanks to require calculations and 
reporting to be undertaken at the county level and by geologic 
formation (by formation type).
    EPA believes that the proposed amendments for subpart W can still 
be implemented for the 2011 reporting year for a couple of reasons. 
First, these amendments are being proposed based on industry concern 
about associating wells with a particular ``field'' given possible 
ambiguity surrounding EIA field designations. While EPA maintains its 
belief that reporting by the field is a viable and workable option, 
however, EPA does acknowledge that counties are readily identifiable, 
and provide clear geographic boundaries. AS a result, implementation of 
this alternative method should be straightforward for facilities. 
Second, if facilities are concerned about their ability to implement 
these provisions for the 2011 reporting year, they may use best 
available monitoring methods (BAMM) pursuant to 40 CFR 98.234(f). In 
the event that facilities have already taken a measurement at the field 
level, they could still use those same measurements for the 2011 
reporting year, but apply them to the sub-basin categories based on 
BAMM.

[[Page 56021]]

    Other amendments to subpart W are proposed to address issues 
identified as a result of working with the affected facilities during 
rule implementation. These proposed revisions provide additional 
flexibility to the sources, or reduce the reporting burden. For 
example, the 2010 final rule required leak detection for emissions from 
dump valves in transportation storage tanks, and if a leak is detected, 
measurement of the quantity of emissions would be required. However, 
industry raised questions as to whether a facility could forgo leak 
detection and directly measure the emissions from leaking dump valves 
under the natural gas transmission industry segment. This action 
provides this additional flexibility, because it reduces burden without 
compromising the quality of the data reported to EPA.
    We are also proposing corrections to terms and definitions in 
certain equations in subpart W. For example, we are proposing to amend 
the calculation for estimating CO2 emissions from acid gas 
removal vents in Equation W-4. Although the existing equation is 
appropriate when the amount of CO2 in gas is relatively low, 
such as 1 percent, the error rate in the estimate increases 
significantly as the amount of CO2 in gas increases. 
Therefore, EPA is proposing a new equation, which uses the exact same 
input parameters and thus will not result in any additional burden to 
reporters, but will improve the quality of the information submitted to 
EPA. These clarifications do not result in additional requirements; 
therefore, we have concluded that reporters can follow part 98, as 
amended, in submitting their first reports to EPA in 2012.
    Finally, we are proposing other technical corrections in subpart W 
that have no impact on a facility's data collection efforts in 2011. 
For example, we are proposing to correct cross references in equations 
and change incorrect use of the term ``facility'' in the definition of 
the source category.
    In summary, these proposed amendments to subpart W generally would 
not require any additional monitoring or information collection above 
what is already included in part 98. Therefore, we expect that sources 
can use the same information that they have been collecting under the 
current version of part 98 to calculate and report GHG emissions for 
2011 and submit reports in 2012 under Part 98, as amended by this 
action.
    We seek comment on whether it is appropriate to implement these 
amendments and incorporate the requirements in the data reported to EPA 
by March 31, 2012. Further, we seek comment on whether there are 
specific provisions in subpart W for which 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 the 2010 final subpart I and subpart W, 
EPA has identified errors in the regulatory language that we are now 
proposing to correct. These issues were identified as a result of 
working with affected industries to implement rules. We have also 
identified certain rule provisions that should be amended to provide 
greater clarity. For additional background information on the questions 
raised, please refer to the Technical Support Document for this 
proposed rulemaking available in the docket to this rulemaking (EPA-HQ-
OAR-2011-0512).
    The amendments we are now proposing include the following types of 
changes:

     Changes to correct cross references within the 
subparts.
     Additional information to allow reporters to better or 
more fully understand compliance obligations in a specific 
provision.
     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 part 98 or any 
other related rulemakings.

A. Subpart A--General Provisions

    Designated Representative. Two industry associations raised 
concerns about the provisions related to determination of the 
designated representative in the context of how the subpart A 
definition would affect subpart W reporters. Through a letter dated 
January 31, 2011, the American Petroleum Institute (API) encouraged EPA 
to reconsider the implications on owners and operators in the onshore 
petroleum and natural gas production segment in the context of the 
provisions in 40 CFR 98.4. Specifically, API was concerned that given 
the definition of ``facility'' for onshore petroleum and natural gas 
production, coupled with the relatively complex ownership structures in 
the industry (as compared to other subparts covered under part 98), EPA 
should modify several requirements in 40 CFR 98.4 (authorization and 
responsibilities of the designated representative). API encouraged EPA 
to eliminate the requirement of notifying co-owners of the designated 
representative selection (40 CFR 98.4(i)(4)(iv)), eliminate the 
requirement for listing of co-owners as part of the certificate of 
representation (40 CFR 98.4(i)(3), and eliminate the requirement for 
new certificates of representation following ownership changes (40 CFR 
98.4(h)).
    Similar concerns were expressed in a letter from Chesapeake Energy 
Corporation (CEC) and the American Exploration & Production Council 
(AXPC) dated January 31, 2011. CEC/AXPC was also concerned that the 
current operational reality in the onshore petroleum and natural gas 
industry would make it difficult for a designated representative to 
make the certifications required in 40 CFR 98.4(i)(4). Specifically, 
CEC/AXPC was concerned about attesting to the fact that the designated 
representative was selected by an agreement binding on the owners and 
operators of the facility, that all owners and operators are fully 
bound by representations of the designated representative, that the 
owners and operators of the facility would be bound by any order issued 
to the designated representative by the administrator or a court, and 
that the designated representative has given written notice of their 
selection and of the agreement by which the designated was selected by 
the owner and operator of the facility.
    EPA maintains, as described in the October 2009 final rule (74 FR 
56357), that the high level of public interest in the data collected 
under this rule, as well as its importance to future policy, warrants 
establishment, by rule pursuant to CAA sections 114, 208, and 
301(a)(1), of a high standard for data quality and consistency and a 
high level of accountability for reported data, which will help ensure 
that the data quality and consistency standard is met. The designated 
representative is the primary point of contact between the owner or 
operator and the EPA. Therefore, it is important that EPA knows who the 
designated representative is, and that the designated representative 
has made the necessary certification statements.

[[Page 56022]]

    EPA recognizes that the onshore petroleum and natural gas industry 
has a different organizational structure and operational realities than 
other industries subject to part 98. As such, in the 2010 final rule 
for subpart W (75 FR 74512), EPA specifically defined who is an onshore 
petroleum and natural gas production owner or operator. Under 40 CFR 
98.238, onshore petroleum and natural gas production owner or operator 
means ``the person or entity who holds the permit to operate petroleum 
and natural gas wells on the drilling permit or an operating permit 
where no drilling permit is issued, which operates an onshore petroleum 
and/or natural gas production facility (as described in 40 CFR 
98.230(a)(2). Where petroleum and natural gas wells operate without a 
drilling or operating permit, the person or entity that pays the state 
or federal business income taxes is considered the owner or operator.'' 
It was EPA's intent that this definition of owner and operator apply 
not only in subpart W, but also in subpart A for the obligations of 
Subpart W ``owners and operators'' (e.g., those related to identifying 
the designated representative and requirement for who must be included 
on the Certificate of Representation (COR)).
    EPA acknowledges that the final subpart W rule is not clear, and it 
could be interpreted that all ``owners'' and all ``operators'', as 
defined in 40 CFR 98.6, are required to identify the designated 
representative for the facility and be held accountable for all 
requirements under 40 CFR 98.4. EPA never intended that 4,000 owners 
and operators, e.g., would have to be listed on the COR, an example 
provided by API in their Petition for Reconsideration. Rather, EPA 
intended that for onshore petroleum and natural gas facilities, the 
references in 40 CFR 98.4 that apply to owner(s) and operator(s) refer 
to the onshore petroleum and natural gas production operator, as 
defined in 40 CFR 98.238. Therefore, we are proposing to explicitly 
make this clarification in 40 CFR 98.1 (Purpose and Scope).
    Definitions: We are proposing amendments to the definition of 
continuous bleed pneumatic device in 40 CFR 98.6 to clarify that 
continuous bleed devices supply gas to process control devices; these 
are not necessarily measurement devices, as suggested by the 2010 final 
rule.
    Similarly, we are proposing to amend the definition of an 
intermittent bleed pneumatic device to clarify that these devices 
automatically maintain the process conditions and that the devices 
discharge all or a portion of the full volume of the actuator 
intermittently.
    Incorporation by Reference (IBR). Finally we are also proposing to 
amend 40 CFR 98.7 (What standardized methods are incorporated by 
reference into this part?) to remove paragraph 40 CFR 98.7(q). As 
elaborated further below, we are proposing to change the calculation 
and reporting requirements for specific equipment in the onshore 
petroleum and natural gas production segment from a ``field'' level, to 
a sub-basin category. Consistent with this proposed amendment, there is 
no longer a need to incorporate the Energy Information Administration 
(EIA) Oil and Gas Field Code Master List, 2008.

B. Subpart I--Electronics Manufacturing

    In this action, EPA is proposing to amend the provisions contained 
within subpart I to calculate and report emissions from fluorinated 
GHGs used as HTFs. First, EPA is proposing to amend the definition of 
HTFs in 40 CFR 98.98, to include all fluorocarbons used as HTFs in the 
electronics manufacturing industry. The definition of HTFs incorporates 
the term ``fluorinated GHGs'' as defined in the general provisions of 
the greenhouse gas reporting rule (subpart A) at 40 CFR 98.6. The 
definition of ``fluorinated greenhouse gas'' in subpart A excludes 
``substances with vapor pressures of less than 1 mm of Hg absolute at 
25 degrees C.'' EPA is proposing to specify that the vapor pressure 
cutoff clause in the subpart A definition of fluorinated GHGs does not 
apply to fluorinated HTFs in subpart I. As a result, emissions of 
fluorinated HTFs with vapor pressures of less than 1 mm of Hg absolute 
at 25 degrees C would no longer be excluded from reporting under 
subpart I. Second, also in the definition of HTFs, EPA is proposing to 
add the phrase ``but not limited to'' before listing examples of 
fluorinated HTFs to ensure that potential future alternatives are 
covered. Third, EPA is proposing to remove the last sentence in the 
definition (``Electronics manufacturers may also use these same 
fluorinated chemicals to clean substrate surfaces or other parts'') and 
move the concept of using HTFs to clean substrate surfaces or other 
parts to the first sentence. Fourth, EPA is proposing minor revisions 
throughout the subpart I regulatory text to clarify the use of the 
terms fluorinated GHGs and fluorinated HTFs (e.g., referring to 
fluorinated HTFs rather than fluorinated GHGs used as HTFs). And last, 
in 40 CFR 98.92(a)(5), under GHGs to report, EPA is proposing to revise 
the clause ``fluorinated GHG emitted from heat transfer use'' to read 
``emissions of fluorinated heat transfer fluids.''
    EPA published Subpart I: Electronics Manufacturing of part 98 on 
December 1, 2010 (75 FR 74774). This subpart requires monitoring and 
reporting of GHG emissions from electronics manufacturing. Included in 
the December 1, 2010 final rule are provisions that require electronics 
manufacturing facilities to calculate and report emissions from the use 
of fluorinated HTFs. Pursuant to 40 CFR 98.93(h), electronics 
manufacturing facilities must calculate HTF emissions using a mass 
balance approach based on: the beginning and end of year inventories; 
acquisitions and disbursements of HTFs; and the nameplate capacities of 
newly installed and removed equipment containing HTFs. For purposes of 
subpart I, HTFs are defined as the following: ``fluorinated GHGs used 
for temperature control, device testing, and soldering in certain types 
of electronic manufacturing production processes. HTFs used in the 
electronics sector include perfluoropolyethers, perfluoroalkanes, 
perfluoroethers, tertiary perfluoroamines, and perfluorocyclic ethers. 
Electronics manufacturers may also use these same fluorinated chemicals 
to clean substrate surfaces and other parts'' (40 CFR 98.98).
    The definition of HTFs in subpart I includes the term ``fluorinated 
greenhouse gases'' (fluorinated GHGs), which is defined in subpart A: 
General Provisions (40 CFR 98.6). EPA initially proposed a definition 
of fluorinated GHGs in the April 2009 proposed rule for part 98 (74 FR 
16448) as follows: ``Fluorinated GHG means sulfur hexafluoride (SF6), 
nitrogen trifluoride (NF3), and any fluorocarbon except for controlled 
substances as defined at 40 CFR part 82, subpart A. In addition to 
(SF6) and NF3, ``fluorinated GHG'' includes but is not limited to any 
hydrofluorocarbon, any perfluorocarbon, any fully fluorinated linear, 
branched or cyclic alkane, ether, tertiary amine or aminoether, any 
perfluoropolyether, and any hydrofluoropolyether.''
    EPA received numerous comments on the definition, particularly in 
regards to Subpart OO-Suppliers of Industrial GHGs. For example, some 
commenters argued that the proposed definition of fluorinated GHGs was 
too broad because it would include nonvolatile materials that could not 
be emitted to the atmosphere. More specifically, one commenter 
suggested establishing a lower vapor pressure limit for fluorinated 
GHGs (heat transfer fluids)

[[Page 56023]]

of 400 Pa (0.004 bar, or three mm Hg absolute) at 25 C.\3\
---------------------------------------------------------------------------

    \3\ For more information on comments and responses, please see 
the preamble to the final rule Mandatory Reporting of Greenhouse 
Gases (74 FFR 56348), and the Response to Public Comment on subpart 
OO (``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to 
Public Comments, subpart OO: Suppliers of Industrial GHGs'' 
available in docket, EPA-HQ-OAR-2008-0508.)
---------------------------------------------------------------------------

    In response to comments, in the 2009 final part 98 (74 FR 56260), 
EPA finalized the following definition of fluorinated GHG: 
``Fluorinated GHG means sulfur hexafluoride (SF6), nitrogen trifluoride 
(NF3), and any fluorocarbon except for controlled substances 
as defined at 40 CFR part 82, subpart A and substances with vapor 
pressures of less than 1 mm of Hg absolute at 25 degrees C. With these 
exceptions, ``fluorinated GHG'' includes but is not limited to any 
hydrofluorocarbon, any perfluorocarbon, any fully fluorinated linear, 
branched or cyclic alkane, ether, tertiary amine or aminoether, any 
perfluoropolyether, and any hydrofluoropolyether.'' As EPA stated in 
the preamble to the final rule, ``This modification ensures that non-
volatile fluorocarbons such as fluoropolymers are excluded from 
reporting requirements, while requiring reporting of fluorocarbons (as 
well as SF6 and NF3) that could reasonably be 
expected to be emitted to the atmosphere'' (74 FR 56348, October 30, 
2009).
    EPA proposed the subpart I definition for HTFs, which included the 
term ``fluorinated GHG,'' in an April 12, 2010 Federal Register notice 
(75 FR 18652). In a December 1, 2010 final rule ``Mandatory Reporting 
of Greenhouse Gases: Additional Sources of Fluorinated GHGs'' (75 FR 
74775), EPA finalized a definition for HTFs that was substantially 
similar to the definition in the April 2010 proposed rule.
    Following publication of the final rule, 3M Company (3M) sought 
reconsideration of the reporting requirements for fluorinated GHGs used 
as HTFs under subpart I. Specifically, in its Petition for 
Reconsideration dated January 28, 2011 (available in docket EPA-HQ-OAR-
2009-0927), 3M stated that ``* * * as currently written the reporting 
requirements for heat transfer fluids will exclude a significant 
portion of fluorinated GHGs used as heat transfer fluids. Thus, the GHG 
emissions associated with heat transfer fluids will not be accurately 
reported under the rule.'' Further, 3M stated, ``By tying the reporting 
requirements for heat transfer fluids to the definition of a 
fluorinated GHG under Sec.  98.6 in Subpart A, the scope of Subpart I's 
reporting requirements are limited to those heat transfer fluids that 
have vapor pressures of > 1 mmHg at 25 degrees C. Although 3M 
understands the reasons behind the vapor pressure threshold in the 
general definition of a fluorinated GHG, the same rationale should not 
apply to heat transfer fluids. Heat transfer fluids are used at 
elevated temperatures and pressures, and as a result the vapor pressure 
of these materials at 1 mm Hg absolute T 25 degrees C is not 
predicative of emissions. Heat transfer fluids are used through a broad 
range of boiling points and are routinely lost from systems primarily 
through mechanical leaks but also from evaporative loss. Once emitted 
from a system, the fate of heat transfer fluids is primarily the 
atmosphere.''
    In addition to the concern that the rule will result in ``dramatic 
under reporting of heat transfer fluid use and emissions,'' 3M also 
raised the concern that ``although all the heat transfer fluids that 
have relatively low global warming potentials will be required to be 
reported as GHGs, a substantial percentage of heat transfer fluids that 
have global warming potentials in the range of 10,000 times that of 
CO2 will be exempt from reporting requirements.'' 
Consequently, 3M argued, ``the rule will likely lead to a migration 
toward use of exempt compounds and an increase in GHG emissions from 
the sector.''
    To address the problem, 3M suggested that subpart I should be 
amended to specify that for reporting requirements under subpart I, the 
vapor pressure cutoff in the general definition of fluorinated GHG does 
not apply to HTFs.
    In finalizing the HTF provisions in subpart I, EPA did not intend 
to exclude a significant portion of fluorocarbon HTFs that can enter 
the atmosphere; any such exclusion was inadvertent. Given the high 
temperatures in which HTFs may be used, EPA believes that such fluids 
are able to enter the atmosphere even when their vapor pressures at 25 
degrees C (77 degrees F) are low. This is because the vapor pressures 
of substances increase as their temperatures increase, and HTFs with 
low vapor pressures are likely to be used in high-temperature 
applications.\4\ (Vapor pressure is an indicator of the rapidity with 
which a substance evaporates.) For example, an HTF with a vapor 
pressure of about 0.2 mm Hg at 25 degrees C might be used at a 
temperature of 140 degrees C for heat transfer applications, where it 
may have a vapor pressure of over 80 mm Hg. Similarly, an HTF with a 
vapor pressure of about 0.1 mm Hg at 25 degrees C might be used for 
vapor phase soldering at a temperature above its boiling point. Under 
these conditions, all of the material is in the vapor phase. Supporting 
technical information is available in the docket (EPA-HQ-OAR-2011-
0512).
---------------------------------------------------------------------------

    \4\ HTFs are selected for particular applications based on their 
viscosities within operating temperature ranges and/or their boiling 
points. For example, for liquid phase applications (e.g., some 
cooling applications) HTFs are selected that have boiling points 
above the operating temperature range and low viscosities at the 
lower operating temperatures. As temperature decreases, viscosity 
increases. Low viscosities are more desirable because they will 
provide good heat transfer and will be easily pumped. For higher 
temperature applications, such as vapor phase soldering, HTFs with 
low vapor pressures--at room temperature (high boiling points) are 
generally selected. (See, e.g., ``Fluorochemicals in Heat Transfer 
Applications: Frequently Asked Questions,'' 3M, available in the 
docket for this rulemaking.)
---------------------------------------------------------------------------

    EPA understands that at any particular temperature, an HTF with a 
low vapor pressure at 25 degrees C is likely to evaporate more slowly 
than an HTF with a higher vapor pressure at 25 degrees C. Nevertheless, 
if the temperature is high, evaporation will occur.
    EPA views data on emissions of HTFs as an important component in 
improving future efforts to characterize GHG emissions from the 
electronics manufacturing sector. EPA believes that the changes being 
proposed today will ensure that all fluorinated HTFs used in 
electronics manufacturing are appropriately monitored and reported 
under subpart I.
    In this action, EPA is proposing that the definition of HTFs in 
subpart I be revised to read as follows: ``Fluorinated heat transfer 
fluids means fluorinated GHGs used for temperature control, device 
testing, cleaning substrate surfaces and other parts, and soldering in 
certain types of electronics manufacturing production processes. For 
fluorinated heat transfer fluids under this subpart I, the lower vapor 
pressure limit of 1 mm of Hg in absolute at 25 degrees C in the 
definition of ``fluorinated greenhouse gas'' in 40 CFR 98.6 shall not 
apply. Fluorinated heat transfer fluids used in the electronics 
manufacturing sector include, but are not limited to, 
perfluoropolyethers, perfluoroalkanes, perfluoroethers, tertiary 
perfluoroamines, and perfluorocyclic ethers.''
    The effect of making the vapor pressure cut-off portion of the 
definition of fluorinated GHGs inapplicable to fluorinated HTFs under 
subpart I would be to subject emissions from fluorinated HTFs that have 
vapor pressures less than one mm of Hg absolute at 25

[[Page 56024]]

degrees C to the reporting requirements. Consequently, EPA would 
receive valuable emissions information on the full range of volatile 
fluorinated HTFs used in electronics manufacturing.
    The purpose of the Mandatory Reporting Rule is to collect accurate 
facility-specific GHG emissions data for use in developing future GHG 
policies and programs. For this reason, EPA believes that the 
definition of HTFs being proposed today is prudent and appropriate 
because it will provide EPA with comprehensive information on emissions 
of fluorinated HTFs. Considering the simple mass balance methodology 
required for reporting emissions of fluorinated HTFs in subpart I, the 
potential value of this information justifies a comprehensive 
definition. If some HTFs (or HTFs in some currently included 
applications) are found to have very low emission rates, this 
information will itself be valuable for informing future GHG policies. 
However, given that HTFs are capable of entering the atmosphere at the 
temperatures where they are used, any conclusion that the emissions of 
some HTFs are low must be supported by actual measurements.
    EPA considered including a modified vapor pressure limit in the 
proposed definition of HTF. One approach we considered was to adopt a 
vapor pressure limit associated with a particular temperature higher 
than 25 degrees C. The goal of such a limit would be to require 
reporting of those HTFs that may readily enter the vapor phase in their 
current and potential future applications. However, we believe that 
today's proposed, application-based definition achieves this goal more 
simply and effectively than would a definition that includes a vapor 
pressure limit associated with a particular temperature higher than 25 
degrees C. First, given the breadth of conditions under which HTFs are 
used currently in the electronics industry, as well as the rapidity of 
technological change within this industry, it would be difficult to 
specify an appropriate upper-limit temperature to which to link the 
vapor pressure. Some applications occur at very high temperatures, and 
those temperatures could conceivably rise in the future. Second, such a 
limit, if not linked to particular HTF applications, could include 
fluorinated chemicals that are used exclusively in low-temperature 
applications where they would not quickly enter the atmosphere if 
released, such as certain lubricants or oils. Third, the major 
application of HTFs is for process cooling. In this application, as 
discussed above, HTFs with lower vapor pressures at a particular 
temperature are likely to be used at higher temperatures. This is a 
systematic relationship that almost guarantees that the HTF will be 
capable of volatilizing at the temperature of use. Similar 
relationships are likely to hold in other applications where viscosity 
or boiling point is a concern, e.g., thermal shock testing. Finally, 
other applications, such as substrate cleaning or vapor phase 
soldering, occur when the material is in the vapor phase. Any upper-
bound temperature linked to a vapor pressure would have to fall above 
the temperatures where vapor phase soldering occurs. The proposed 
definition achieves the same goal much more directly by including the 
applications ``soldering,'' ``temperature control,'' ``device 
testing,'' and ``cleaning substrate surfaces.''
    Another approach we considered was to require reporting only of 
HTFs that achieve a particular vapor pressure (e.g., 1 mm Hg absolute) 
at their maximum temperature of use, where the maximum temperature of 
use could vary from facility to facility or even application to 
application within a facility. This approach would explicitly focus 
monitoring and reporting on those HTFs and applications where 
volatilization could occur. However, because the coverage of particular 
chemicals would depend on their maximum temperature of use within a 
particular facility or application, this approach would be 
significantly more difficult to implement and enforce than the 
proposed, application-based definition. Facilities would be required to 
investigate the temperatures at which each HTF is used and to 
distinguish between low- and high-temperature applications of the same 
HTF in developing emissions estimates. The proposed approach, in 
contrast, would clearly define the applicability of the rule and would 
enable facilities (and EPA) to rely on facility-wide mass-balances to 
estimate emissions of particular chemicals.
    EPA does not intend for its definition of HTFs to include greases 
or lubricants such as those used in vacuum pump applications because 
such applications do not typically occur at temperatures at which the 
lubricants would volatilize. EPA does not believe that the current or 
proposed definitions include such lubricants. However, EPA requests 
comment on whether the definition should be amended to explicitly 
exclude lubrication or other applications. To address situations in 
which a particular chemical may be used in both HTF and non-HTF 
applications, EPA also requests comment on whether we should give 
reporters flexibility to report under 40 CFR 98.93(h) either a 
chemical's emissions from all applications or its emissions from only 
the applications included in the HTF definition. This would give 
facilities the option to avoid maintaining a separate supply of the 
chemical for purposes of tracking HTF emissions, as would otherwise be 
required for the mass-balance calculation. Emissions from the non-HTF 
applications would presumably make up a small fraction of the total.
    The narrow exception to the vapor pressure cutoff would only apply 
to fluorinated HTFs used in the electronics manufacturing industry; EPA 
continues to believe that the vapor pressure cutoff is appropriate to 
maintain in the definition of fluorinated GHG in 40 CFR 82 subpart A 
(e.g., for purposes of the industrial gas supply provisions at subpart 
OO). EPA is not aware of other fluorocarbon applications in which the 
vapor pressure of the fluorocarbon falls below 1 millimeter of Hg at 25 
degrees C but typically rises significantly above it at the temperature 
of use.
    In addition, EPA is also proposing four other minor amendments to 
the regulatory text related to fluorinated HTFs. First, in the 
definition of HTF (40 CFR 98.98), EPA is proposing to add the phrase 
``but not limited to'' before listing examples of fluorinated HTFs. 
Electronics manufacturing is an innovative and quickly evolving 
industry in which new chemicals are frequently adopted. EPA is 
proposing this change to ensure that potential future alternatives are 
covered. Second, also in the definition of HTFs (40 CFR 98.98), EPA is 
proposing to delete the last sentence (``Electronics manufacturers may 
also use these same fluorinated chemicals to clean substrate surfaces 
or other parts'') and move the concept of cleaning substrates surfaces 
or other parts to the first sentence. EPA is proposing this change to 
improve readability of the definition. Third, EPA is proposing minor 
revisions throughout the subpart I regulatory text to clarify the use 
of the terms fluorinated GHGs and fluorinated HTFs (e.g., referring to 
fluorinated HTFs rather than fluorinated GHGs used as HTFs). For 
example, in instances where EPA used the term ``fluorinated GHG used as 
heat transfer fluids,'' EPA is proposing to use ``fluorinated heat 
transfer fluids.'' Where EPA refers to HTFs, EPA does not intend the 
full definition of fluorinated GHGs (as defined in subpart A) to apply. 
And last, in 40 CFR 98.92(a)(5), under GHGs to report, EPA is proposing 
to revise the clause ``fluorinated GHG emitted from heat

[[Page 56025]]

transfer use'' to read ``emissions of fluorinated heat transfer 
fluids.'' EPA is proposing this change to clarify that emissions of 
fluorinated HTFs, not just fluorinated GHGs, are required to be 
reported under subpart I. In addition, EPA is proposing the change to 
clarify the Agency's intention that emissions from HTFs can occur 
through all phases of the equipment's lifetime, including installation, 
use, servicing, and disposal. Under subpart I, all of those emissions 
of HTFs should be calculated and reported.
    EPA does not anticipate an increase in burden resulting from these 
proposed changes because this action is clarifying the intent of the 
requirements finalized in subpart I. In finalizing the reporting 
requirements for fluorinated HTFs, EPA did not intend to exclude 
fluorocarbons that can enter the atmosphere under the conditions in 
which HTFs are used in the electronics manufacturing industry. EPA's 
burden estimates were based on reporting of all fluorinated HTFs; 
therefore, the clarification of intent does not impose additional 
burden on reporters.
    EPA requests comment on the proposed amendments to the HTF 
provisions of subpart I. In particular, EPA requests comment whether 
the proposed definition effectively captures fluorinated HTFs used in 
electronics manufacturing (i.e., whether any type of fluorinated HTFs 
other than those included in the proposed definition are currently 
being used or are anticipated to be used in the future for electronics 
manufacturing). EPA also requests comment on whether any other 
conforming changes need to be made.
    EPA plans to address the comments on these proposed amendments and 
publish the final amendments to subpart I before the end of 2011. 
Therefore, EPA requests comment on whether to require electronics 
manufacturing facilities to estimate and report 2011 emissions in 2012 
of the HTFs that would be newly included in the scope of subpart I if 
today's proposed rule were finalized. Specifically, EPA requests 
comment on whether information collected as part of routine business 
practices, such as records of HTF stocks, disbursements, and 
acquisitions, could be used to estimate 2011 emissions to be reported 
in 2012. If it is not feasible to estimate HTF emissions in 2011 for 
substances that are currently excluded from reporting using information 
collected as part of routine business practices, EPA requests detailed 
information illustrating why it is not feasible.

C. 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 in response to petitions submitted to EPA for 
reconsideration, as well as clarifications to specified provisions in 
the rule to ensure consistency with subpart W, and across all subparts, 
where appropriate. In addition, several technical corrections are 
proposed to clarify provisions that were either erroneous or unclear to 
reporters.
    The following section describes EPA's proposed amendments. We first 
discuss the proposed amendments related to field-level reporting in the 
onshore petroleum and natural gas production section, since this 
proposed amendment affects multiple emissions sources (well 
completions, well workovers, well venting for liquids unloading, and 
onshore storage tanks) and also affects many sections of the rule 
(e.g., calculation, monitoring and quality assurance/quality control 
(QA/QC), and the data reporting requirements). Following the discussion 
for onshore production, we discuss the proposed amendments to the 
Definition of the Source Category (40 CFR 98.230), GHG's to Report (40 
CFR 98.232), Calculating GHG Emissions (40 CFR 98.233), Monitoring and 
QA/QC Requirements (40 CFR 98.234), Data Reporting Requirements (40 CFR 
98.236) and Records to be Retained (40 CFR 98.237) under subpart W.
    Sub-Basin Category for Onshore Petroleum and Natural Gas 
Production. EPA has received several requests to reconsider the use of 
a field-level measurement plan for emission sources (mainly monitoring 
of GHGs from well unloading, well completions, and well workovers) that 
require one measurement per field as designated by the U.S. Energy 
Information Administration (EIA) Field Code Master List (FCML). Onshore 
petroleum and natural gas production reporters have expressed concerns 
over the use of this field designation and proposed that a sub-basin 
category be assigned instead of a field designation to take 
measurements. Specifically, petitioners indicated that EPA has not 
clarified how reporting entities are supposed to map wells to a 
particular field. They contested that there are no coordinates provided 
in the EIA FCML 2008. They also suggested there is no formal way to 
designate appropriate field names and the rule does not have a 
mechanism to deal with wells that are not in a recognized field in the 
EIA Master List. Mapping wells to the proper field is central to 
compliance with the rule, they assert, because the rule requires 
aggregation of information by field for the different emissions 
sources. To address these concerns, industry petitioned EPA to replace 
the field-level approach with a ``sub-basin category'' approach.
    In general, EPA continues to believe that the field-level 
designation is workable, although perhaps not the only means of 
obtaining representative emissions estimates. EPA has determined that 
the EIA field codes are developed using field names that operators 
provide and agree on with States, which is finally provided by the 
States to the EIA. Therefore, EPA believes that operators can determine 
the EIA field they are in using the EIA field codes. EPA also agrees 
that the 2010 final rule did not state a clear mechanism to address 
wells in fields that were not included in the EIA FCML. However, EPA 
has determined that this is not an acute problem. EPA has analyzed the 
EIA FCML for several years and found that the changes in the database 
from year to year are not significant. For example, there were only 30 
changes in field definitions between 2007 and 2008 of the total 64,454 
fields in the database. Similar numbers result from comparing 2006 with 
2007 (170 changes in field definition of a total 63,873 fields in the 
database) and comparing 2006 with 2005 (44 changes in field definition 
of a total 63,356 fields in the database). The changes include both the 
revision of some field names as well as new additions.
    In this action we are proposing an alternative approach to replace 
``field-level'' with ``sub-basin categories.'' EPA considered, but is 
not proposing at this time modifications to the current field level 
reporting method that would address the outstanding concerns raised by 
industry. Specifically, EPA considered an amendment that would allow 
reporters to use a temporary field name when submitting reports to EPA 
in instances where a well does not fall within a designated EIA field 
code. This alternative approach would include a provision for reporters 
to report a preliminary field name where a field has not been formally 
designated by the State and as such may not yet be included in the EIA 
FCML. These preliminary fields entered by the reporter would be 
annotated in the final report to EPA and would be flagged in the data 
system for further follow up to determine the final field name 
designated by the State. Because States

[[Page 56026]]

operate on different schedules for which final determinations are made 
on field designation requests, reporters would be required to certify 
with official documentation submitted to EPA upon each reporting period 
on the status of their field designation request. Under this alternate 
approach, for field designations that are made prior to the next 
reporting date, reporters should confirm the field designation with 
official documentation during the next submission of their emission 
report to EPA. This proposed method would address concerns raised by 
industry about fields not yet included in the EIA FCML.
    In addition, EPA is considering but did not propose a provision 
that would delineate how reporters would determine appropriate field 
names for wells for which the designated field is unknown due to 
unclear location or coordinates of the well. Under such a provision, 
reporters would determine the EIA FCML field for a given well by 
determining the well coordinates and follow the procedures outlined in 
the 2008 EIA FCML or most approximate year's documentation that 
accompanies the EIA FCML field list which outlines the method for 
matching up well coordinates with field names. Although EPA is 
proposing an alternative means to calculate and report emissions based 
on a sub-basin category, we are seeking comment on this approach to 
modify the current field-level calculation and reporting requirements 
for utilizing the EIA FCML for sampling. Although EPA maintains that 
the current field level calculation and reporting requirements are 
feasible and provide representative emissions estimates (with an 
amendment to clarify how to address non-designated fields), EPA is 
proposing an alternative sub-basin approach that we believe also 
achieves an appropriate level of representativeness. Please see 
Economic Impact Analysis Memorandum in Docket ID EPA-HQ-OAR-2001-0512. 
This proposed sub-basin category classification would provide similar 
quality data as the EIA FCML designation but believes will also address 
some of the questions and concerns regarding current implementation of 
the field-level approach.
    The foundation of the proposed sub-basin approach is defining a 
sub-basin category through the use of a county level designation and 
the distinction of the type of hydrocarbon formation. The various 
hydrocarbon formations can be grouped into four categories: 
conventional, coal bed methane, tight formations, and shale. For 
example, wells producing coal bed methane from formation ``X'' with 
wellhead coordinates within county ``A'' would be one sub-basin 
category. Further, wells producing from tight formation ``Y'' with 
wellhead coordinates within county ``A'' would be a second sub-basin 
category. In the event that a specific county includes more than one 
formation (e.g., coal bed methane and tight sands), then the reporter 
would use the most specific designation (e.g., coal bed methane).
    With this basic formulation of sub-basin category, EPA has 
determined that it is necessary to provide a second level of 
classification to get a representative emissions profile of emissions 
sources. For example, the emissions from well completions or hydraulic 
fracturing can vary by several multiples within the same producing 
formation because of different fracture zones and fracture extent. 
Similarly, well liquids unloading emissions can vary widely because of 
different well dimensions and liquid accumulation. EPA further notes 
that the activity of emissions sources are highly concentrated within 
certain counties and formation types. For example, of the 3,143 
counties in the United States, there are only 54 counties that had any 
form of well completion in year 2010. In such a case, where 25,000 well 
completions are concentrated in 54 counties, a single measurement from 
a sub-basin category, may not be sufficiently representative.
    Therefore, to obtain a sufficient number of data points to be able 
to characterize the variability in the emissions profile, EPA is 
proposing a measurement plan that uses some operational criteria to 
generate more than one sample per sub-basin category for specific 
emissions sources. Specifically, EPA is proposing the use of pressure 
ranges for liquids unloading measurements, because the volume of gas 
released during an unloading is related to the wellhead pressure. For 
example, reporters would take one measurement per pressure range within 
a sub-basin category. An example of pressure ranges is 0-25 psig, > 25-
60 psig, > 60-110 psig, > 110-200 psig, and 200 psig and above. These 
pressure ranges were developed based on an analysis that reviewed well 
data from the HPDI(copyright) database which determined the 
optimal pressure ranges that also minimize variability of a single data 
point as a representation of that pressure range. For more information 
on this analysis, please see the Technical Support Document for this 
proposed rulemaking in the docket.
    The rationale for applying these pressure ranges is that wells 
generally have more liquids unloading problems when they are flowing at 
low pressures and lower velocities. Hence, it is reasonable to provide 
more ranges in the lower pressure spectrum. EPA expects to see few 
wells over 200 psig that necessitate liquids unloading to atmospheric 
pressure. For well completions and workovers, EPA is proposing to 
divide the population of wells between vertical and horizontal wells, 
as defined in proposed amended 40 CFR 98.238, and then using a 
graduated number of measurements per number of wells completed or 
worked over in these categories. For example, one measurement per 25 
wells with hydraulic fracture, two measurements per 50 wells with 
hydraulic fracture, three measurements per 100 wells with hydraulic 
fracture, and four measurements per 200 or more wells with hydraulic 
fracture. EPA understands that there are many operational factors that 
impact the magnitude of emissions from well hydraulic fracture 
completions and workovers and therefore is proposing more than one 
measurement where there is a larger number of wells in the sub-basin 
category.
    Source Category Definitions. In general, we are proposing several 
amendments to the source category definitions to clarify the boundaries 
between the different industry segments. The proposed amendments below 
seek merely to clarify coverage in the rule and were not intended to 
change who is required to report within and across the industry 
segments.
    Onshore Petroleum and Natural Gas Production. We are proposing 
several amendments to the definition for the onshore petroleum and 
natural gas production (also referred to as onshore production) 
industry segment in 40 CFR 98.230(a)(2). EPA received feedback from 
reporters on the finalized definition for the onshore production 
industry segment on November 30, 2010 (see 75 FR 74489) requesting 
clarification on the term ``associated with a well-pad.'' Specifically, 
reporters requested clarification on what the term ``associated with a 
well-pad'' meant in the context of the boundaries of the onshore 
production industry segment. Reporters stated that there is unclear 
demarcation between equipment that are considered part of the onshore 
production industry segment and equipment that are considered part of 
the onshore natural gas processing industry segment.
    To address concerns on the meaning of ''associated with a well-
pad'', EPA is first proposing to revise the term itself to state that 
the onshore production

[[Page 56027]]

industry segment includes that equipment that is ``on a single well-pad 
or associated with a single well-pad.'' EPA has determined that 
equipment located on a single well-pad is considered part of the 
onshore production industry segment irrespective of the hydrocarbon 
streams that it is handling. For example, a separator located on a 
well-pad that handles hydrocarbon streams from multiple well-pads would 
be considered to be part of the onshore production industry segment, 
i.e. equipment that is not located on a well-pad would be considered to 
be associated with a well-pad. Also, hydrocarbon streams from multiple 
wellheads located on a single well-pad is considered to be a single 
hydrocarbon stream from that well-pad.
    In addition, EPA is proposing to clarify in the onshore production 
industry segment definition that dehydrators that are on a single well-
pad or associated with a single well-pad are included as types of 
equipment that is considered part of this segment. Following 
promulgation of subpart W in November 2010, EPA received several 
questions from the reporting community requesting clarification on 
whether or not dehydrators associated with a single well-pad would be a 
part of the industry segment. It was EPA's intent that these 
dehydrators that are on a well-pad or associated with a single well-pad 
be considered part of the onshore production industry segment. EPA also 
received similar requests for clarification on whether or not storage 
vessels, not necessarily the entire storage facility, were also 
considered part of the onshore production industry segment. To address 
these concerns, EPA is proposing to clarify in the definition that both 
dehydrators and storage vessels are included in the equipment list that 
are considered part of the onshore production industry segment. 
Finally, EPA proposes to clarify that Enhanced Oil Recovery (EOR) that 
use either CO2 or natural gas are a part of the source category. The 
equipment located on a well-pad is part of the onshore production 
industry segment irrespective of the hydrocarbon streams located on a 
well-pad.
    Onshore Natural Gas Processing. EPA is proposing several 
clarifications to the onshore natural gas processing industry segment 
definition in 40 CFR 98.230(a)(3). By letter dated January 31, 2011, 
the Gas Processors Association (GPA), CEC/AXPC, and API, all expressed 
concerns with overlap between the onshore production, onshore natural 
gas processing, and onshore natural gas transmission industry segments. 
API stated that ``The definitions of the industry categories `onshore 
oil and gas production' and `natural gas processing' do not provide a 
clear line between onshore oil and gas production, gas gathering/
collection and booster stations, and natural gas processing 
facilities.'' The letter stated ``API is particularly concerned that 
the final rule could be interpreted to include gathering and boosting 
stations in the processing sector, despite EPA's stated intent to 
exclude gathering and boosting stations from coverage at this time.'' 
Industry raised concerns that boosting stations would be covered under 
the finalized natural gas processing industry segment definition 
because they typically have processes that require removal of liquids 
for operation of specific equipment that boost gas pressure. For 
example, scrubbers are used upstream of compressors to take out any 
liquids for optimal operation of the compression equipment. However, 
the presence of scrubbers in and of itself should not result in the 
facility being defined as a processing facility.
    To address the concerns with boundaries between industry segments, 
we are proposing several revisions to clarify our intent. First we are 
proposing to strike the term ``and recovers'' from the first sentence 
in order to more clearly characterize the unique activities performed 
at the processing plant. Processing plants extract heavy hydrocarbons 
and non hydrocarbon gases from the gaseous phase of an inlet feed to 
the plant. By inclusion of the term ``recovers'' in the industry 
segment definition, the natural gas processing plant definition may 
have been incorrectly interpreted to bring in other types of processes 
that were not intended to be covered.
    We are also proposing to clarify that this industry segment 
includes one or a combination of the following three processes: 
Separation of natural gas liquids (NGLs) from natural gas, separation 
of non-methane gases from produced natural gas, or separation of NGLs 
into one or more component mixtures. This proposed revision would 
clarify that the natural gas processing industry segment differs from 
what typically happens at boosting stations in that natural gas 
processing plants typically perform one or more of these processes, 
whereas boosting stations do not.
    We are also proposing a clarification on what separation means by 
stating that separation means one or more of the following processes: 
Forced extraction of natural gas liquids, sulfur and carbon dioxide 
removal, fractionation of NGLs, or the capture of CO2 separated from 
natural gas streams.
    We are proposing to strike the term ``this industry segment does 
not include reporting of emissions from gathering lines and boosting 
stations'' because the edits proposed above clarify what ``onshore 
natural gas processing'' means, and therefore it is unnecessary to 
discuss that which is excluded. Further, if we had decided to maintain 
the ``gathering lines and boosting'' stations in the rule, EPA would 
have to propose and finalize a definition of the term ``gathering line 
and boosting'' station, which EPA has previously noted we intend to 
consider in a future rulemaking (75 FR 74468).
    Finally we are proposing to strike the term ``facility'' and 
replace it with the term ``plant'' as ``facility'' has a specific 
definition in 40 CFR 98.6 that was not intended here. A natural gas 
processing plant may be located at a facility that also contains other 
source categories covered by 40 CFR part 98.
    Onshore Natural Gas Transmission Compression. EPA is proposing 
several clarifications to the onshore natural gas transmission 
compression industry segment definition in 40 CFR 98.230(a)(4). As 
noted earlier, by letter dated January 31, 2011, API, CEC/AXPC, and GPA 
raised their concerns that the boundaries between the onshore 
production, onshore natural gas processing, and onshore natural gas 
transmission compression industry segment boundaries were unclear based 
on the provisions in the November 30, 2010 final rule.
    First, we are proposing to strike the term ``at elevated pressure'' 
because it was not clear what ``elevated pressure'' meant. For example, 
elevated with respect to what baseline? Based on questions received on 
the definition for transmission compressor stations, we have proposed 
to clearly define transmission pipelines using a widely accepted 
designation for what is a transmission pipeline, avoiding the need to 
retain the language of ``elevated pressure.'' We are proposing to 
define in 40 CFR 98.238 that a transmission pipeline means a Federal 
Energy Regulatory Commission (FERC) rate-regulated interstate pipeline, 
a state rate-regulated intrastate pipeline, or a pipeline that falls 
under the ``Hinshaw Exemption'' as referenced in the Natural Gas Act.
    Next, we are proposing to clarify the end points between which a 
natural gas transmission compression facility would move natural gas. 
Specifically, we are proposing to explicitly state that natural gas 
transmission compression facilities not only move natural gas from

[[Page 56028]]

production fields or gas processing plants, but also move natural gas 
coming from other transmission compressors. In addition, we are 
proposing to explicitly state that natural gas transmission compression 
facilities may move natural gas into not only distribution pipelines, 
but also into liquefied natural gas storage or into underground 
storage.
    We are also proposing to strike the term ``natural gas 
dehydration'' from the industry segment definition because this term 
does not represent a unique characteristic to facilities with natural 
gas transmission compression. We believe that deleting this term from 
the definition of the natural gas transmission compression industry 
segment, will result in this industry segment definition being more 
representative and accurate. Finally, as described above under onshore 
natural gas processing, we are proposing to strike the reference to 
``gathering lines and boosting stations'' and ``facility.''
    Natural Gas Distribution. EPA is proposing several amendments to 
the natural gas distribution industry segment definition to further 
clarify its intent. First, we are proposing in 40 CFR 98.230(a)(8) to 
eliminate the term ``city gate station'' and add the term ``meter-
regulating station.'' The term ``city gate,'' was used in the 2010 
final rule because it was believed to be widely used throughout the 
natural gas distribution industry. However, since publication, we have 
learned that the term can have several meanings and the interpretation 
of what is a ``city gate'' station may vary among potential reporters. 
By letter dated March 2, 2011 from the American Gas Association, it was 
stated that ``[t]he term `city gate' is widely used in the industry, 
but unfortunately it means different things to different companies. It 
can mean the place where an LDC takes custody of natural gas from the 
upstream supplier (either directly from a producer or from an 
interstate pipeline company). The term `city gate' is also used by some 
to refer to the place where natural gas is conveyed into a lower 
pressure distribution system for a town or city--either directly from 
the upstream supplier (producer or interstate pipeline) or from the 
LDC's own intrastate high pressure transmission pipelines. Some 
companies do not use the term `city gate' to refer to the situation 
where natural gas goes from the company's own transmission pipes to one 
of its distribution systems. Instead, these companies may use other 
terms such as `district regulator' or `metering and regulating 
stations,' or `M&R' equipment, and these terms also can have varying 
meanings.''
    Further, subpart A provides a definition for ``city gate,'' which 
was intended to apply to subpart NN and is based on financial custody 
transfer. Whereas the connotation of the term city gate as defined in 
subpart A works sufficiently for subpart NN, it has created confusion 
for subpart W and does not clearly identify the types of facilities EPA 
intended to cover. The amendments that EPA is proposing are designed to 
more clearly portray EPA's intent using language readily understandable 
to industry.
    First, we are proposing to strike the parenthetical term ``(not 
interstate transmission pipelines or intrastate transmission 
pipelines).'' The parenthetical was deemed unnecessary because EPA is 
proposing to add a definition for ``distribution pipeline'' in 40 CFR 
98.238 that clarifies that ``distribution pipelines'' are only those 
designated as such by the Pipeline and Hazardous Material Safety 
Administration (PHMSA). Next, we are proposing to replace the term 
``city gate'' with ``meter-regulating'' station. Because of the wide 
range of views in industry on the meaning of the term ``city gate'' EPA 
is proposing to remove the term ``city gate'' from subpart W and 
replace it with a term that reflects the types of activities occurring 
at the stations of interest. Specifically, we are proposing to add a 
definition for the term ``meter-regulating station'' in 40 CFR 98.238 
to mean, ``An above ground station that meters the flow rate, regulates 
the pressure, or both, of natural gas in a natural gas distribution 
facility. This does not include customer meters, customer regulators, 
or farm taps.'' With this change, EPA intends to clarify a key concept 
in the natural gas distribution segment definition, but does not intend 
to change who is actually covered by the rule's requirements.
    EPA is proposing to strike the terms ``excluding customer meters'' 
and ``physically deliver natural gas to end users'' because the 
proposed definition for ``meter-regulator'' stations already addresses 
this exclusion.
    Finally, we are proposing to clarify in the industry segment 
definition that we are only seeking for LDCs that are within a single 
state, consistent with the definition for LDCs in subpart NN.
    Greenhouse Gases to Report. We are proposing several amendments to 
the subpart W provisions on the greenhouse gases that must be reported.
    We are proposing to amend 40 CFR 98.232(c) to clarify that the 
equipment listed in 98.232(c)(1) thru (22) are for equipment on a 
single well-pad or associated with a single well-pad in order to make 
the language consistent with the proposed changes to the onshore 
production industry segment definition in 40 CFR 98.230(a)(2) described 
above.
    We are proposing to amend 40 CFR 98.232(i) by replacing the term 
``custody transfer city gate station'' with the term ``transmission-
distribution transfer station'' and replacing the term ``non-custody 
transfer station'' with the term ``metering-regulating station.'' EPA 
is proposing this amendment to clarify that the sources covered be 
consistent with the proposed terms for the natural gas distribution 
industry segment in 40 CFR 98.230(a)(8). We are also proposing to amend 
the source types by removing the text ``Customer meters are excluded.'' 
The exclusion is already covered in both the industry segment 
definition and in the definition of ``metering-regulating station'' 
provided in 40 CFR 98.238 and does not provide added clarity in this 
context. Next, we are proposing to strike 40 CFR 98.232(j) in order to 
address concerns raised that the inclusion of this provision resulted 
in confusion amongst reporters as they were unsure how this provision 
aligned with the flare emissions that are captured under the applicable 
emissions source calculations throughout 40 CFR 98.233. In addition to 
the proposal to strike 40 CFR 98.232(j), we are proposing to revise the 
introductory sentences to 40 CFR 98.232(e), (f), (g), (h), and (i) to 
clarify that N2O emissions, which are the primary GHG 
emission from flaring, are also required to be reported under these 
industry segments. This proposed amendment also clarifies that flare 
emissions must only be calculated where ``flare stacks'' are either 
specifically identified in a specific industry segment (e.g., onshore 
natural gas processing) or where an emissions source that is covered in 
an industry segment is routed to a flare (e.g., centrifugal compressors 
under onshore natural gas transmission).
    Finally, we are proposing to further clarify in 40 CFR 98.232(k) 
that the onshore production and natural gas distribution industry 
segments are to report their combustion emissions under subpart W, 
while the remaining industry segments are to report their combustion 
emissions under subpart C of part 98.
    Calculating Greenhouse Gas Emissions. We are proposing several 
clarifications, corrections, and amendments throughout 40 CFR 98.233.
    Natural Gas Pneumatic Device Venting. EPA is proposing to revise 
Equation W-1 in 40 CFR 98.233(a) by

[[Page 56029]]

adding 40 CFR 98.233(a)(3) that allows the type of pneumatic devices to 
be determined using engineering estimation based on best available 
information. The proposed amendment for pneumatic devices was in 
response to questions received about how to determine whether a 
pneumatic device is high bleed or low bleed and the unanticipated 
burden for industry if they would have to measure the bleed rate of all 
pneumatic devices in order to determine how to characterize each 
pneumatic device.
    EPA is also proposing to amend Equation W-1, to include a parameter 
``T'' that estimates the total number of hours the devices were 
operational. Previously, this equation assumed that all natural gas 
pneumatic devices were operational all year, which would overestimate 
the emissions where the pneumatic devices operate less than a full 
year. Overall, we are proposing these amendments to Equation W-1 to 
more accurately reflect operating conditions for natural gas pneumatic 
device venting. Furthermore, EPA is clarifying in the definition for 
``GHGi'' that compositions in 40 CFR 98.233(u) may be used 
for the onshore petroleum and natural gas production, onshore natural 
gas transmission compression, and underground natural gas storage 
industry segments.
    In addition, with respect to the pneumatic device venting category, 
we are proposing in 40 CFR 98.236(c)(1)(iv) to clarify that emissions 
should be reported collectively for all high bleed pneumatic devices, 
then separately for all intermittent bleed pneumatic devices, and 
separately for all low bleed pneumatic devices. The 2010 final rule 
stated merely ``report emissions collectively.'' The proposed amendment 
is consistent with how data are collected and emissions calculated.
    Natural Gas Driven Pneumatic Pump Venting. We are proposing to 
amend Equation W-2 in 40 CFR 98.233(c), which is used for calculating 
GHG emissions from natural gas pneumatic pump venting, to include a 
parameter ``T'' that estimates the total amount of hours the pumps were 
operational. Previously, this equation assumed that all natural gas 
pneumatic pumps were operational all year, which would overestimate the 
emissions where the pneumatic devices operate less than a full year. We 
are proposing this amendment to Equation W-2 to more accurately reflect 
operating conditions for natural gas pneumatic pump venting.
    Acid Gas Removal Vents. We are proposing to amend the calculation 
for estimating CO2 emissions from acid gas removal vents in 
Equation W-4 in 40 CFR 98.233(d). EPA notes that the equation in the 
2010 final rule is an approximation and works well when the amount of 
CO2 in gas is relatively low, such as 1 percent. However, 
the error rate in the estimate increases significantly as the amount of 
CO2 in gas increases. Therefore, EPA is proposing a new 
equation, which uses the exact same input parameters and thus will not 
result in any additional burden to reporters, but will improve the 
quality of the information submitted to EPA.
    We are also proposing to amend 40 CFR 98.233(d)(1) to specify that 
the use of CEMS is required if a CO2 concentration monitor 
and volumetric flow rate monitor are installed. This amendment was made 
to clarify what conditions must be met to satisfy the subpart C: 
Stationary Combustion Tier 4 calculation requirement for Acid Gas 
Removal vents and to make the requirements consistent in subpart W 
where use of CEMS is required.
    In 40 CFR 98.236(c)(3) we are proposing to clarify that reporting 
of CO2 content should reflect the annual average of the 
measurements undertaken in 40 CFR 98.233(d). The 2010 final rule was 
not clear on whether or not to aggregate the measurements, and if so, 
how.
    Dehydrator Vents. EPA is proposing several amendments to the 
provisions in 40 CFR 98.233(e) for calculating GHGs from dehydrator 
vents. First, we are proposing to clarify that gases other than natural 
gas, such as nitrogen, flash gas from the flash tanks, or dry gas from 
the absorber, that are used as stripping gases satisfy the requirements 
stated in 40 CFR 98.233(e)(1) introductory language. The final rule 
explicitly stated that natural gas was the gas considered to be the 
stripping gas. We are proposing this amendment to more accurately 
reflect operating conditions for glycol dehydrators in which gases 
other than natural gas are used as stripping gases.
    We are also proposing to amend 40 CFR 98.233(e)(6) to clarify that 
GHG mass emissions from glycol dehydrators are to be calculated from 
volumetric GHG emissions using calculations in 40 CFR 98.233(v). In 
addition, we are proposing to clarify that only for dehydrators that 
use desiccant should GHG volumetric and mass emissions be calculated 
using paragraphs 40 CFR 98.233(u) and 98.233(v). We are proposing this 
amendment to account for calculation methodology 1 and 2, 40 CFR 
98.233(e)(1)-(e)(3), that calculates total GHGi volumetric emissions in 
standard cubic feet and will only need conversion to GHG mass emissions 
using 40 CFR 98.233(v).
    With respect to the data reporting requirements, we are proposing 
to clarify the requirement to report vented and flared emissions 
individually. In the 2010 final rule, EPA intended that vented 
emissions be reported as one value, and flared emissions as a separate 
value. However, because these were entered in the same sub-paragraph, 
40 CFR 98.236(c)(4)(i)(J), there was some ambiguity as to the 
aggregation for reporting. Therefore, EPA is proposing to create 
separate reporting requirements for vented and flared emissions. A 
similar amendment is proposed for 40 CFR 98.236(c)(4)(ii)(D).
    Also for dehydrators, EPA is proposing to clarify that in 
specifying whether any vent gas controls have been used, the owners or 
operators should report which vent gas controls were used.
    Well Venting for Liquids Unloadings. First, we are proposing to 
revise 40 CFR 98.233(f) methodology 1, methodology 2, and methodology 3 
such that sampling would be done in a sub-basin category as opposed to 
the field level as described earlier in Section II.C. of this preamble 
(Sub-basin Category for Onshore Petroleum and Natural Gas Production).
    In the technical corrections rule, EPA proposed several technical 
corrections to the provisions in 40 CFR 98.233(f) including corrections 
to Equation W-8, W-9, and their respective definitions. In today's 
action, we are proposing additional revisions to Equations W-8 and W-9 
and their respective definitions. Because both proposed actions affect 
the same paragraph of the rule, for clarity the part 98 amendatory 
language at the end of this preamble contain the full set of revisions 
from both proposed actions. The changes proposed today are explained 
below in this preamble.
    First we are proposing to revise Equation W-8 by correcting the 
definition for parameter Ea,n to be Es,n to 
accurately reflect that the calculated emissions should be in standard 
conditions and not actual conditions. The proposed revision from actual 
conditions to standard conditions was made to be more uniform in 
approach to calculate emissions. The parameters in Equation W-8 have 
been made applicable to each venting instance, q, and for each well, p, 
in a pressure grouping and sub-basin category. These changes are 
notational amendments that correct the summation operation. Next, we 
are proposing to amend the definition for ``SFR'' which is the average 
sales flowrate to state that the

[[Page 56030]]

average sales flow rate of gas is to be obtained at standard 
conditions, and also that Equation W-33 may be used to convert the 
sales flow rate from actual to standard conditions. In addition, the 
definition for parameter WDwp has been clarified to mean the 
distance between the lowest packer to the bottom of the well. We are 
also proposing to remove 40 CFR 98.233(f)(2)(i) to remove redundancy 
with 40 CFR 98.233(f)(4). As stated previously, we are proposing to 
amend Equation W-9 in the same manner as Equation W-8: By revising the 
definition for ``Ea,n'' to accurately state that the 
definition should result in standard conditions, thus 
``Es,n'', and by revising the definition for SFR to state 
that the average sales flow rate is to be calculated at standard 
conditions using Equation W-33; and the parameters, where applicable, 
have been made applicable to each venting event, q for each well, p, in 
a pressure grouping and sub-basin category to correct the summation. 
Finally, we are proposing to amend Equation W-8 and W-9 to account for 
a change in aggregation from field level to sub-basin category for 
reporting.
    For Calculation Method 1, where a representative measurement is 
taken from one well unloading and then applied to all other wells of a 
similar type, EPA is defining the categorization of ``similar types'' 
by five pressure ranges and three tubing diameters. The pressure ranges 
were optimized using HPDI well counts in 5 psig pressure increments 
from zero gauge pressure to 200 psig. The fifth ``unbounded'' pressure 
range is ``greater than 200 psig,'' which EPA believes will have very 
few well liquids unloading venting to the atmosphere. The three tubing 
diameter ranges, equal or less than 1 inch, greater than 1 inch and 
equal or less than 2 inch, and greater than 2 inch, were derived from 
gas well tubing suppliers' specifications. The relevancy of these 
pressure ranges and tubing diameter ranges is that liquids unloading 
venting is dependent on both the shut-in pressure of the reservoir 
(shut-in by liquids accumulation) and velocity of gas pushing liquids 
up the tubing, which is a function of tubing diameter.
    Finally, in the data reporting requirements in 40 CFR 98.236(c)(5), 
we are proposing to make a harmonizing change, consistent with the 
amendments described above in (Sub-basin Category for Onshore Petroleum 
and Natural Gas Production), that reporting should be for each well 
tubing diameter grouping and pressure grouping within each sub-basin 
category.
    Gas Well Venting During Completions and Workovers From Hydraulic 
Fracturing. We are proposing several amendments to 40 CFR 98.233(g) to 
account for the proposed change in aggregation from field level to sub-
basin category for taking measurements. For example, we are replacing 
the term ``field'' with ``sub-basin and well type combination'' in the 
definitions and clarifying that the GHG emissions are determined for 
each sub-basin and well type combination. For further discussion on the 
proposed changes from field level calculations and reporting to sub-
basin category, please refer to Section II.C of this preamble (Sub-
basin Category for Onshore Petroleum and Natural Gas Production).
    We are also proposing to revise equation W-10 by including a 
provision to account for the time period in which we believe normal 
production of a well would be established. In this action, we are 
revising equation W-10 by defining a parameter, FRM, which would 
represent the ratio of emissions (FRp) to the average 30 day 
production from the well immediately following hydraulic fracturing 
(PRP). The emissions, FRp, which in the final 
rule as the average flow rate in cubic feet per hour converted to 
standard conditions, are calculated using W-11A and W-11B. FRM is 
calculated using the newly assigned Equation W-12. We believe that this 
proposed revision will more accurately represent the production flow 
from a well immediately following a well or completion using hydraulic 
fracturing and will more accurately represent when a completion or 
workover ends and when normal production begins. Finally, in Equation 
W-10, EPA is proposing to add the parameter W, which is the number of 
wells completed or worked over using hydraulic fracturing in a sub-
basin and well type combination, and, where appropriate, made the 
parameters applicable to each well p. This amendment corrects the 
summation operator to make it mathematically accurate.
    EPA also added Equation W-11C, which allows reporters to determine 
whether the well flow rate of gas during venting to the atmosphere or a 
flare (i.e., FRWP, is sonic or sub-sonic flow. Thus, 
reporters can determine whether to use Equation W-11A, which is for 
sub-sonic flow, or Equation W-11B, which is for sonic flow.
    We are also proposing several minor edits to 40 CFR 98.233(g)(3) 
and 40 CFR 98.233(g)(5) to clarify that all requirements in 40 CFR 
98.233(g) apply to gas well venting during completions and workovers 
from hydraulic fracturing, consistent with the emission source name of 
``Gas well venting during completions and workovers from hydraulic 
fracturing''.
    In 40 CFR 98.233(g)(3) we are also proposing to delete the 
reference to how to calculate the volume of recovered completion or 
workover gas. The first sentence in that paragraph is already clear 
that company records may be used, therefore the second sentence does 
not provide any additional information and is duplicative.
    We are proposing several harmonizing changes to the data reporting 
requirements for this emissions source. We are proposing to indicate 
that reporting is required for each ``sub-basin category'' and well 
type (horizontal or vertical). We are also proposing to clarify that 
reporting of reduced emissions completions for both well completions 
and workovers is required. Although this information is required to be 
collected for both well completions and well workovers, EPA 
inadvertently omitted the reporting requirement for reduced emissions 
completions for well workovers.
    Also in 40 CFR 98.236, we are proposing to clarify that reporters 
are only required to count the number of workovers that flare or vent 
gas to the atmosphere. There is no reporting requirement for workovers 
that do not flare or vent gas.
    Gas Well Venting During Completions and Workovers Without Hydraulic 
Fracturing. In this section we are proposing to strike the term ``well 
workovers not involving hydraulic fracturing'' from the introductory 
text in paragraph (h) because it was repetitive.
    Second we are proposing to replace the term ``field'' used in the 
definition for the parameter ``Nwo'' and ``f'' for the same 
reasons stated in Section II.C. of this preamble (Sub-basin Category 
for Onshore Petroleum and Natural Gas Production).
    Finally, EPA is proposing to amend the summation operator in 
Equation W-13 to make it mathematically accurate. This includes making 
specific parameters in Equation W-13 applicable to each well 
completion, p.
    Blowdown Vent Stacks. In a previous action we proposed amendments 
to the introductory sentences to 40 CFR 98.233(i). In this action, 
based on additional questions received during implementation of subpart 
W, we are proposing to further clarify the types of blowdowns that EPA 
intended to cover. First, we are proposing to delete ``to atmosphere'' 
because not every blowdown will result in the blowdown chamber being 
brought to atmospheric pressure. Operators often release only

[[Page 56031]]

part of the gas in the blowdown chamber and maintain it at low 
pressure. It was always EPA's intent to cover these types of 
``blowdowns'' and thus we are proposing to delete ``to atmosphere''. 
Further we are clarifying that we only intend to cover the types of 
blowdowns typically tracked by operators for planned maintenance or 
emergency shutdowns. EPA had earlier proposed to exclude emergency 
shutdowns in a previous action. However, EPA has since been informed 
that operators track emergency shutdowns already. Therefore, EPA is 
proposing to require emergency shutdowns to be reported. In addition, 
we did not intend to capture blowdowns that are not typically tracked 
by operators, such as pressure release valve releases designed to keep 
equipment under safe operating mode.
    EPA has also considered other factors that could impact emissions 
from blowdowns, for example compressibility. We have considered 
accounting for gas compressibility but have not proposed this because 
we believe that the effort in adjusting for a compressibility factor 
outweighs the benefits in terms of increased accuracy. EPA seeks 
comments on why such an allowance should be provided and how to 
standardize this option so that those who choose to use it all do so in 
the same way.
    Also in this action, we are proposing to revise the numbering of 
Equation W-14b and include an additional Equation, W-14b that will take 
into account that a chamber may not be blown down to atmospheric 
pressure, and will allow facilities the option of tracking blowdowns by 
each occurrence by blowdown volume. It has come to EPA's attention that 
some facilities may log blowdowns at a facility by individual blowdown 
occurrence. To enable facilities to retain their current tracking 
system, we are proposing to add an option for calculating blowdown 
emissions by equipment type. This option for tracking blowdowns would 
not impact data quality. Harmonizing changes in 40 CFR 98.236(c)(7) are 
being proposed to account for these amendments.
    Lastly, we are proposing to include a default composition for the 
natural gas transmission industry segment, and for the LNG storage and 
underground storage segments. EPA received feedback from industry that 
a default composition of 95 percent methane and 1 percent 
CO2 was a representative breakdown of the gas composition at 
these types of facilities while limiting burden and should be 
acceptable. EPA agrees that a default composition of 95 percent methane 
and 1 percent CO2 is appropriate because the composition of 
natural gas is monitored by transmission compression companies and 
regulated by FERC.
    Onshore Production Storage Tanks. EPA is proposing to replace the 
term ``field'' in 40 CFR 98.233(j)(1)(vii)(B), 40 CFR 
98.233(j)(1)(vii)(C), and 40 CFR 98.233(j)(3)(i) with ``sub-basin 
category'' consistent with the proposed amendments described in Section 
II.C, (Sub-basin Category for Onshore Petroleum and Natural Gas 
Production), of this preamble. We are also proposing to clarify this 
level of reporting in the data reporting requirements in 40 CFR 
98.236(c)(8).
    Also in the data reporting requirements, we are proposing to 
clarify the reporting requirement in 40 CFR 98.236(c)(8)(i), 
98.236(c)(8)(ii) and 98.236(c)(8)(iii) that reporters must report 
vented, flared, and recovered emissions individually for Calculation 
Methodology 1 and 2. This is consistent with the calculation 
requirements.
    Transmission Storage Tanks. We are proposing to revise 40 CFR 
98.233(k) to include an additional provision such that reporters would 
now have the option of directly measuring the transmission storage 
tanks while bypassing an initial screening with the optical gas imaging 
instrument. EPA received feedback from industry that some owners and 
operators would prefer to simply measure the tank annually without 
having to be required to screen the tank vapors with a camera first. We 
agree that allowing facilities to directly measure the emissions, 
without first requiring leak detection, does not compromise data 
quality, but could enable facilities to meet the requirements of the 
rule with lower burden. Therefore, in this action, EPA is proposing to 
allow operators to either screen their tanks first by using the optical 
gas imaging instrument for 5 continuous minutes and if a leak is 
detected, measure the leak according to the provisions in 40 CFR 98.234 
consistent with the 2010 final rule, or measure the tank vent vapors 
for 5 minutes using either a flow meter, calibrated bag, or high volume 
sampler according to the provisions outlined in 40 CFR 98.234.
    Finally, with respect to the data reporting requirements in 40 CFR 
98.236(c)(9), as described further above, we are proposing to clarify 
the separate reporting requirements for vented and flared emissions.
    Well Testing Venting and Flaring. EPA is proposing In amendments to 
the data reporting requirements in 40 CFR 98.236(c)(10). Specifically, 
we are proposing to add a reporting requirement for the emissions of 
the flaring gas collectively. This is consistent with other proposed 
clarifications to report flared emissions separately.
    EPA is considering, and has not proposed, using the production rate 
to estimate volume of emission from gas wells that produce dry gas. EPA 
is soliciting comments on this suggested provision for gas wells.
    EPA has received several requests to exclude the well testing 
venting and flaring emissions source from the rule. Industry has 
informed EPA that this source has very little, if any, emissions 
because the well testing is almost exclusively performed in a closed 
system using a ``test separator,'' which industry has stated would 
result in zero emissions.
    EPA has reviewed this request and in general, EPA continues to 
believe that well testing venting and flaring is a relevant source in 
the onshore petroleum and natural gas production industry segment. In 
addition, EPA has determined that during well testing, some states 
allow companies to flare sour gas for a maximum of 72 or 144 hours. EPA 
has concluded that this approach would result in emissions from this 
source that should be reported under this rule. If, however, for some 
reason reporters do not have any emissions from this source (for e.g., 
states do not allow venting or flaring from well testing), they would 
report zero emissions.
    Thus, EPA is retaining well testing venting and flaring in the 
rule. However, EPA is seeking comment on how to reduce or eliminate 
burden in cases where companies verify that zero emissions are 
associated with this potential source, such as when a closed loop 
system is employed.
    Associated Gas Venting and Flaring. EPA is proposing to revise 40 
CFR 98.233(m) to replace the term ``field'' with the term ``sub-basin 
category'' for the same reasons outlined in Section II.C. (Sub-basin 
Category for Onshore Petroleum and Natural Gas Production) of this 
preamble.
    Flare Stack Emissions. We are proposing two amendments in 40 CFR 
98.233(n)(2) to clarify how to determine gas compositions for 
hydrocarbon streams going to flare. First, we are proposing to amend 40 
CFR 98.233(n)(2)(ii) to clarify that reporters must use the GHG mole 
percent in feed natural gas for all streams for onshore natural gas 
processing plants that solely fractionate a liquid stream. EPA is 
proposing this amendment to address lack of clarity in the final 
provisions

[[Page 56032]]

which did not explicitly state how natural gas processing plants which 
only fractionate liquid streams would determine their gas compositions. 
We are also proposing to clarify in 40 CFR 98.233(n)(2)(iii) that 
methane, in addition to ethane, propane, butane, pentane-plus and mixed 
light hydrocarbons, should be accounted for when the stream going to 
the flare is a hydrocarbon product stream. This proposed technical 
correction, to add methane, ensures that paragraph 40 CFR 
98.233(n)(2)(iii) is consistent with the equation.
    In addition, we are proposing to clarify the summation operator in 
W-21 to make it mathematically correct. We are also clarifying that 
source types in 40 CFR 98.233 that send emissions to a flare must 
determine volumetric flow rate, parameter ``Va'', in Equation W-19 
through W-20, at actual conditions.
    We are also proposing to clarify that the volume of gas sent to the 
flare should be calculated in actual conditions. This is consistent 
with other proposed changes throughout this revision that clarify the 
use of actual versus standard conditions.
    In addition, we are proposing to allow facilities the option to use 
a continuous emissions monitoring system (CEMS) to estimate GHG 
emissions from flares. EPA received questions as to why CEMS were 
allowed for use for AGR vents, for example, but not for flares. We did 
not intend to unnecessarily limit the measurement options for flares, 
and therefore are proposing to add the option to use CEMS.
    The proposed text clarifies that the use of CEMS is required if a 
CO2 concentration monitor and volumetric flow rate monitor 
are installed and that optionally a user may install a CO2 
concentration monitor and volumetric flow rate monitor to be eligible 
to use the Tier 4 methodology. When CEMS are used to calculate 
emissions for flare stacks the use of equations W-19 to W-21 would no 
longer apply. With the relatively high quantity of unburned methane in 
the emissions from flares, EPA has identified that it is not 
appropriate to use the CH4 calculation methodology in 
subpart C as most flared gases will not be fuels listed in Table C-1 of 
subpart C. EPA is seeking comment on what form an equation should take 
that would calculate CH4 and N2O for flares that 
are monitored by CEMS. One option is to calculate the CH4 by 
multiplying the concentration of CO2 measured by the CEMS by 
the fraction of CH4 that was not combusted as determined by 
flare efficiency.
    In the data reporting requirements in 40 CFR 98.236(c)(12) we are 
proposing to add reporting requirements consistent with the calculation 
requirements in Equations W-19 through W-21. Specifically, we are 
proposing to add reporting of uncombusted CH4, combusted and 
uncombusted CO2 and combustion-related N2O 
emissions. The proposed amendments ensure consistency across the 
calculation, monitoring and reporting requirements.
    Centrifugal Compressor Venting. Consistent with other 
clarifications throughout this proposed rule, we are proposing to 
clarify in the definition for the term MTm in Equation W-24 that flow 
measurements should be determined in standard cubic feet per hour.
    Leak Detection and Leaker Emission Factors.
    We are proposing to revise 40 CFR 98.233(q)(8) to remove the term 
``city gate stations at custody transfer'' and replace with 
``transmission-distribution transfer stations'' for the reasons 
described earlier in Section II.C of this preamble. We are also 
proposing to remove the term ``meters and regulators'' and replace with 
above ground ``metering-regulating stations''. The term ``meter-
regulating'' is a term that we are proposing to define in this action, 
as described earlier in Section II.C of this preamble.
    The revisions to terminology for natural gas distribution 
facilities have been proposed to clearly identify who is covered under 
the distribution segment of subpart W, and the sources for which leak 
detection and measurement are required and those sources for which an 
emission factor can be used. Based on feedback received from industry, 
there may be concerns that the emission factors developed at the 
transmission-distribution transfer stations are not representative of 
emissions at other above ground metering-regulating stations. Although 
we are not proposing changes to the approach for applying emission 
factors to above ground metering-regulating stations in this action, we 
are seeking comment on alternative approaches, or data that may be 
used, for determining emissions factors for above ground metering-
regulating stations. Based on comments received, EPA may consider 
future amendments to the rule.
    In a separate action, (76 FR 37300) EPA is proposing to expand the 
final BAMM provisions to cover all facilities subject to subpart W, and 
allow reporters the option to use best available monitoring methods 
(BAMM) for all of 2011 without being required to submit a request for 
approval to the Administrator. For natural gas distribution facilities 
at transmission-distribution transfer stations, this would allow 
facilities to estimate the number of equipment leaks and the equipment 
sources themselves using BAMM as provided in the rule, along with the 
total time the component was found leaking and operational, as outlined 
in Equation W-30. This emission factor could then be used for other 
above ground metering-regulating stations within the facility boundary.
    EPA is proposing to clarify the summation operator in W-30 to make 
it mathematically correct. This clarification includes amending x to be 
the total number of each equipment leak source and adding 
Tp, which is the total time the component p was found 
leaking and operational. We are proposing to revise the parameter 
GHGi. For industry segments listed in 98.230 (a)(4) and 
(a)(5), GHGi has been revised to 0.974 for CH4 
and 1.0 x 10-2 for CO2. For industry segments listed in 
(a)(6) and (a)(7), GHGi equals 1 for CH4 and 0 
for CO2. For industry segments listed in (a)(8), 
GHGi equals 1 for CH4 and 1.1 x 10-2 
CO2 (See Technical Support Document Memo (TSD) in Docket ID 
EPA-HQ-OAR-2011-0512 for further details).
    Next we are proposing two amendments in 40 CFR 98.236(c)(15). We 
are proposing to amend the reporting requirements in 40 CFR 
98.236(c)(15)(i)(C) to clarify that owners or operators must report 
CH4 emissions collectively by equipment type and 
CO2 emissions collectively by equipment type. The 
calculation methodologies in 40 CFR 98.233(q), as finalized in the 
rule, require reporters to calculate CH4 emissions and 
CO2 emissions separately per source with equipment leaks. We 
are proposing this amendment to clarify that applicable reporters must 
report the CH4 emissions collectively by equipment type and 
CO2 emissions collectively by equipment type. We are also 
proposing to correct the reporting requirement in 40 CFR 
98.236(c)(15)(ii)(A) to not include onshore natural gas processing. 
This source category is not required to use population emission 
factors. This amendment is associated with the amendment to Equation W-
31 in 40 CFR 98.233(r) discussed in Calculating Greenhouse Gas 
Emissions.
    Population Count and Emission Factors. We are proposing several 
amendments in 40 CFR 98.233(r). First we are proposing to amend the 
population emission factor definition in equation W-31 by replacing the 
term ``non-custody transfer city-gate'' with above grade ``metering-
regulating station'' for the reason stated above in this preamble. We 
are also clarifying

[[Page 56033]]

that the count in equation W-31 applies to the number of ``meter/
regulator runs'' at all ``metering-regulating stations'' combined.
    We are also proposing to amend the term ``count'' in W-31 as 
follows to elaborate and clarify how each industry segment should count 
the total number of equipment/components. In that same equation, we are 
also proposing to revise the definition for GHGi by 
referring to 40 CFR 98.233(u) and deleting the composition specified 
for each industry segment.
    Next, EPA is proposing to amend 40 CFR 98.233(r)(2)(i) to 
explicitly state how meters and piping are to be counted. Table 1-B of 
the 2010 final rule was developed using activity data from the 1996 
EPA/Gas Research Institute Study (1996 EPA/GRI Study), Methane 
Emissions from the U.S. Natural Gas Industry. For all major equipment 
that are not specifically listed, the 1996 EPA/GRI Study categorized 
all components at a well-pad under the meters/piping category. 
Therefore, owners or operators should use one count of meters/piping 
per well-pad.
    Further, consistent with proposed amendments described above, EPA 
is proposing to amend 40 CFR 98.233(r)(6)(ii) by referring to 
``metering-regulating stations'' in place of ``city gate'' and to 
clarify that the emission factor for meter/regulator runs at all 
metering-regulating stations in equation W-32 is based on leak 
detection performed at ``transmission-distribution transfer stations''. 
EPA is also amending 40 CFR 98.233(r)(6)(i) to clarify that below grade 
meters and regulators apply to below grade ``metering-regulation 
stations''.
    Lastly, we are proposing revisions to equation W-32 that include 
revisions to the definitions for EF, Es,i, and ``Count'' 
again to clarify the terminology change away from ``custody transfer'' 
to above ground ``metering-regulating'' stations. We are also proposing 
the inclusion of a conversion factor to convert to hourly emissions. 
Consequently, we are proposing to amend the conversion in Equation W-32 
in 40 CFR 98.233(r) so that the equation yields an EF in cubic feet per 
meter per hour to be used in Equation W-31 for above ground metering-
regulating stations. Finally, the summation operator has been removed 
in Equation W-32 because Es,i represents annual volumetric 
GHGi emissions at all T-D transfer stations, making the 
summation operator redundant.
    In addition to the proposed calculation amendments described above, 
we are also proposing to replace the term ``field'' with ``sub-basin 
category'' in the reporting for onshore production, consistent with the 
proposed change to sub-basin calculation and reporting.
    Volumetric Emissions. We are proposing to amend 40 CFR 98.233(t) to 
clarify that reporters should use actual temperature and pressure and 
adjust to standard conditions. The phrase ``by converting actual 
temperature and pressure of natural gas emissions to standard 
temperature and pressure of natural gas'' was deleted because it is 
redundant.
    GHG Volumetric Emissions. We are proposing to amend 40 CFR 
98.233(u) to include 95 percent methane/1 percent CO2 
default gas composition for the natural gas transmissions industry 
segment, along with the LNG storage and underground storage industry 
segments. Again, as described above, EPA agrees that a default 
composition of 95 percent methane and 1 percent CO2 is 
appropriate because the composition of natural gas is monitored 
consistently and regulated by FERC.
    We are also proposing to strike the reference to the term ``field'' 
in 40 CFR 98.233(u) and replace with ``sub-basin category'' for the 
reasons outlined in Section II.C. of this preamble (Sub-Basin Category 
Reporting for Onshore Petroleum and Natural Gas Production).
    We are also proposing to clarify that the GHG mole fraction that is 
determined without using a continuous gas analyzer may be determined 
using an annual average instead of the most recent gas composition 
based on available analysis in a sub-basin entity.
    GHG Mass Emissions. We are proposing to clarify in the definitions 
to equation W-36 that the equation applies to N2O emissions 
as well. N2O emissions are calculated from stationary 
combustion and flares, and the proposed edit is necessary to convert 
the mass emissions of N2O to carbon dioxide equivalents of 
gas. EOR injection pump blowdown. We are proposing to clarify in the 
equation that only CO2 emissions are calculated. The 
variables Massc,i has been changed to Massc, 
CO2, and GHGi has been changed to 
GHGCO2.
    Onshore Production and Distribution Combustion Emissions. In a 
previous action, EPA proposed several revisions to 40 CFR 98.233(z) 
including corrections to Equations W-39 and 40. In this action, we are 
proposing additional amendments to clarify when owners or operators of 
onshore production and distribution facilities must use the methods in 
40 CFR subpart C to calculate combustion-related emissions and when 
they must use the methods in 40 CFR 98.233(z) to calculate combustion-
related emissions. We are proposing to clarify that facilities using 
subpart C to calculate emissions are not limited to the use of tier 1, 
but rather may use any tier. Regardless of the tier used, the facility 
must follow the corresponding calculation, monitoring and reporting 
requirements of that tier.
    We are also proposing to amend the requirements for units 
combusting field gas or process vent gas. The 2010 final rule required 
the use of a continuous flow meter, if present. Use of a continuous 
flow meter would have necessitated calibration requirements per 40 CFR 
98.3(i). These calibration requirements were disproportionately 
burdensome for these relatively small disperse units, particularly 
given that facilities that currently do not have a flow meter in place 
could use company records. In this action, we are proposing to amend 
the requirements to allow the use of company records for this 
equipment.
    Onshore Production and Distribution Equipment Threshold for 
Internal Combustion Equipment. In letters dating January 31, 2011 and 
March 5, 2011 from API and AGA, respectively, EPA received petitions to 
reconsider an exemption for internal combustion engines similar to that 
which was in the final subpart W rule (75 FR 74458, November 30, 2010) 
for external combustion engines. These requests from the onshore 
petroleum and natural gas production and natural gas distribution 
reporters were to provide respite for reporting of emissions from 
internal combustion equipment that are brought in temporarily for 
maintenance and construction. Some reporters have requested complete 
exemption such that combustion equipment that fall below a specific 
threshold would be exempt from reporting.
    EPA considered, but decided not to propose an exemption for 
reporting for internal combustion engines. EPA decided not to propose 
amendments because data currently are not available to sufficiently 
characterize these upstream emissions. For example, the volume of fuel 
consumed, especially at wellhead natural gas compressors, is not being 
monitored and only limited data, voluntarily reported, are available 
through the Energy Information Administration.
    Although EPA has decided not to propose a threshold due to lack of 
availability of a comprehensive data source from which to develop 
policy, we acknowledge that there is potentially small internal 
combustion equipment outside of compressors. In considering a

[[Page 56034]]

potential equipment threshold for non-compressor internal combustion 
engines, EPA collected and reviewed data on the size ranges of small, 
portable internal combustion engines that may be brought to a wellhead 
for periodic maintenance and construction. Such equipment would 
include, for example, electric generators for arc welding, electric 
generators powering portable flood-lighting, and electrical generators 
or gasoline engines powering air compressors (for sand blasting or 
pneumatic tools). For lighting, the industrial generators were almost 
exclusively below 12 horsepower (hp), with the highest found being 13.9 
hp. For welding machines, we assumed that they would use standard 
portable generators, since specific information on these types of 
machines was scarce. Most portable industrial generators are rated 
between 15-40 hp, with the largest one found being 67 hp. EPA 
determined that 130 horsepower (double the largest size found) would 
exclude virtually all small portable or stationary internal combustion 
engines, but is much smaller than the 5 mmBtu/hour exclusion for 
external combustion sources and equates to about 1 mmBtu/hour. EPA is 
seeking comments on whether a 1 mmBtu/hour equipment threshold for 
internal combustion engines that are not driven by natural gas is 
reasonable. We also seek comment on EPA's position that combustion-
related emissions at compressors should not be excluded from reporting, 
regardless of size and where EPA can find reliable estimates of natural 
gas consumption.
    EPA is proposing to clarify the summation operator in Equation W-39 
to make it mathematically correct. In addition, EPA is proposing to 
clarify in Equation W-40 that N2O mass emissions are 
calculated by changing the parameter N2O to Masss, 
N2O.
    In specific, EPA is soliciting comments as to why emissions from 
specific internal combustion related equipment should not be reported 
including the size of the equipment that should be excluded along with 
supporting data.
    Monitoring and QA/QC Requirements. We are proposing several 
amendments to the monitoring and QA/QC requirements in 40 CFR 98.234.
    First, we are proposing to amend the language in 40 CFR 
98.234(a)(1) by first removing and reserving the text in 40 CFR 
98.234(a)(4) and combining it with 40 CFR 98.234(a)(1), thus resulting 
in one consolidated paragraph. We are also proposing to state 
explicitly that video recordings are not required under subpart W. As 
noted in the Response to Comments to the 2010 final rule,\5\ EPA did 
not intend to require retention of a video recording of the leak 
detection using optical gas imaging instruments for reporting to EPA 
under subpart W of the greenhouse gas reporting rule. However, some of 
the references to the Alternate Work Practice suggested that EPA 
intended that facilities retain these records onsite.
---------------------------------------------------------------------------

    \5\ Response to Comments Document: Subpart W--Petroleum and 
Natural Gas Systems, part 2, page 28. Comment Number: EPA-HQ-OAR-
2009-0923-1039-23.
---------------------------------------------------------------------------

    Next, we are proposing to amend the language in 40 CFR 98.234(a)(2) 
to state that Method 21 compliant instruments may be used to monitor 
inaccessible emissions sources. This amendment increases flexibility in 
monitoring requirements and reduces the burden on the industry, without 
compromising data quality.
    Further, based on questions raised by industry, we are proposing to 
amend 40 CFR 98.234(a)(5) by revising the acoustic leak detection 
device provisions to use a different model of acoustic detector, one 
that does not have a through-valve leakage correlation, thereby 
allowing leakage to be measured by other methods if a leak is found. 
However, EPA is proposing to clarify that not all types of acoustic 
detectors are allowed. In particular the ``gun'' type instrument that 
is aimed at the equipment from a distance to detect the acoustic signal 
of leakage is not an allowable instrument. This type cannot distinguish 
between external leakage to the atmosphere from internal, through-valve 
leakage, which is the objective for specifying this device. EPA is 
proposing to further specify that the ``stethoscope'' type acoustic 
detector that senses through valve leakage when put in contact with the 
valve body, but does not have the leakage estimating correlations, may 
be used.
    We are also proposing editorial revisions in 40 CFR 98.234(c) for 
calibrated bagging to specify that those using the calibrated bag for 
sampling, must ensure that the emissions must be at a temperature below 
that which the bag manufacturer specifies for safe handling.
    Data Reporting Requirements. We are proposing several amendments 
and clarifications throughout 40 CFR 98.236 in order to address 
questions received about how data should be reported. Many of the data 
reporting requirements were lacking clarity with respect to the level 
of reporting. Based on the questions received, as well as EPA's 
experience gained in developing the electronic GHG reporting tool (e-
GGRT), which provided EPA a better understanding of the clarity 
necessary in the data reporting requirements, EPA is proposing the 
following changes.
    In cases where technical amendments were already proposed for 
individual emissions sources above, EPA has described the corresponding 
proposed amendments to the reporting requirements along with the 
technical amendments. This section outlines any remaining proposed 
amendments to the data reporting requirements not already described 
above.
    First we are proposing to clarify the data reporting requirements 
for offshore petroleum and natural gas production facilities in 40 CFR 
98.236(b). Specifically, the 2010 final rule was not clear in terms of 
which gases were required to be reported and the data elements for 
reporting. Consistent with the calculation requirements, we are 
proposing to clarify that facilities containing the offshore petroleum 
and natural gas production segment would be required to report 
emissions of CH4, CO2, and N2O as 
applicable to the source type (in metric tons CO2e per year 
at standard conditions) individually for all the emissions source types 
listed in the most recent BOEMRE study.
    Next, in the introductory paragraph for 40 CFR 98.236(c) we are 
proposing to clarify that vented emissions should be reported 
separately from flared emissions. We have specified which source types 
require separate calculation of flared emissions, but EPA is taking 
comment on whether any source types that have process gas routed to 
flares were excluded from having specific reporting requirements 
established for flares.
    We are proposing to make changes to the data reporting requirements 
for local distribution companies, consistent with the proposed 
amendments to 40 CFR 98.230(a)(8). Specifically, we are proposing to 
replace ``custody transfer'' with ``transmission-distribution 
transfer'' station and replace ``non-custody transfer'' with ``above 
ground metering-regulating station.'' In addition, we are proposing to 
require the reporting of counts and emissions of both above grade and 
below grade stations for each of metering-regulating stations and 
``transmission-distribution transfer stations.''
    Finally, EPA seeks some basic information on average API gravity of 
the hydrocarbon liquids produced, gas to oil ratio, and low pressure 
separator pressure per sub-basin entity. It is EPA's understanding that 
his information is already known to reporters. EPA will use these 
facility sub-basin

[[Page 56035]]

characteristics to characterize other emissions sources across 
different sub-basins.''
    Records that must be retained. EPA is proposing to add the 
following recordkeeping requirement: ``The records required under Sec.  
98.3(g)(2)(i) shall include an explanation of how company records, 
engineering estimation, or best available information are used to 
calculate each applicable parameter under this subpart.'' While EPA 
believes this requirement is already included in 40 CFR 98.3(g)(2)(i) 
where the records for ``The GHG emissions calculations and methods 
used'' requirement is made, EPA believes that adding this statement to 
the recordkeeping requirements in subpart W will provide facilities 
with further clarity on the records they are required to keep. This 
clarification is intended to make clear that stating company records, 
engineering estimation, or best available information were used is not 
enough to satisfy the requirement in 40 CFR 98.3(g)(2)(i). This 
requirement is intended to parallel a similar requirement for subpart C 
specified in 40 CFR 98.34(f) and referenced in 40 CFR 98.37.
    Definitions. We are proposing to amend, and in some cases, add 
definitions to 40 CFR 98.238 to further clarify rule requirements.
    Associated With a Single Well-Pad. We are proposing to add a 
definition for ``associated with a single well-pad'' to clearly 
demarcate the boundary of onshore production. EPA proposes that the 
association be defined by the hydrocarbon stream from a single well-
pad. The association with a single well-pad ends where the stream from 
a single well-pad is combined with streams from one or more additional 
single well-pads, where the point of combination is located off that 
single well-pad. In addition, we are stating that this definition does 
not include storage and condensate tanks that are located downstream of 
the point of combination. For gas contained in crude oil or condensate 
flowing under pressure off a single well-pad to a gas-liquid separator 
or tank, or comingled with flow from other well-pads, 40 CFR 98.233(j) 
requires reporting of the gas content that may be released from the oil 
or condensate in an atmospheric pressure fixed roof storage tank. We 
have determined that the conditions of the pressurized oil or 
condensate (i.e., gravity, pressure, temperature, flow rate) are 
commonly known by the well owner/operator, and the amount of gas that 
may be released from the oil or condensate with a pressure reduction 
can be determined most appropriately by the well owner/operator.
    Distribution Pipeline. EPA is proposing to include a definition for 
distribution pipelines to add clarity on its intent on coverage for the 
natural gas distribution industry segment. We are proposing to use a 
widely accepted definition for distribution pipelines, specifically, 
those designated as such by the Pipeline and Hazardous Material Safety 
Administration (PHMSA).
    Facility With Respect to Natural Gas Distribution. EPA is proposing 
to revise the definition for natural gas distribution by replacing the 
term ``metering stations, and regulating;''with the term ``metering-
regulating.'' EPA is proposing to include a definition for the term 
above ground ``metering-regulating station'' to clarify where leak 
detection and monitoring is required in the 2010 final rule.
    Farm Taps. EPA is proposing to revise the definition for farm taps 
in 40 CFR 98.238 by striking the unnecessary phrase ``The gas may or 
may not be metered, but always does not pass through a city gate 
station.''
    Flare. We are proposing to add a definition of flare specific for 
subpart W to address questions received during implementation about 
what constitutes a flare. The proposed definition clarifies that a 
flare may be either at ground level or elevated and uses an open or 
enclosed flame to combust waste gases without energy recovery. This 
definition for subpart W is intended to be inclusive of devices that 
combust waste gases without energy recovery. This broad, all-inclusive 
definition for subpart W is necessitated by the wide variety of waste 
gas combustion devices that are or may be used in the different 
segments of subpart W, all for the same purpose and having the same 
effect of combustion emissions of hydrocarbon gases.
    Forced Extraction of Natural Gas Liquids. We are proposing to add a 
definition for forced extraction to restrict it to specific processes. 
EPA determined that it was necessary to develop this more precise 
definition because many industry questions pointed to the confusion 
between processing plants, gas gathering stations and wellheads, where 
similar equipment and processes are conducted as at some, but not all, 
processing plants that EPA determined should be subject to this rule. 
Those similar processes. These processes in and of themselves do not 
make a facility a ``processing plant.'' Furthermore, the Oil & Gas 
Journal annual survey of gas processing plants is primarily focused on 
those that fractionate, leaving out known, large gas plants that 
separate NGLs or condition gas, but do not fractionate, and are clearly 
not gathering booster stations. The key principle that EPA is 
attempting to clarify through this definition is the separation of 
heavier hydrocarbons in the vapor phase of natural gas delivered to a 
plant, excluding the simple gravity separation of liquids entrained in 
the gas. This principle is ``forced extraction,'' as defined here.
    Horizontal Well. With the change from field level reporting to sub-
basin category, EPA is proposing to add a distinction for calculating 
emissions from horizontal wells and vertical wells. We are proposing to 
define horizontal well to mean a well bore that has a planned deviation 
from primarily vertical to a primarily horizontal inclination or 
declination tracking in parallel with and through the target formation.
    Sub-Basin Category. With the change from field level reporting to 
sub-basin category, EPA is proposing to add a definition for sub-basin 
category to mean a subdivision of a basin into the unique combination 
of wells with the surface coordinates within the boundaries of an 
individual county and subsurface completion in one or more of each of 
the following four formation types: Conventional with > 0.1 millidarcy 
permeability, and unconventional with <= 0.1 millidarcy permeability 
shale, coal seam, and other tight reservoir rock, all of which are 
unconventional with <= 0.1 millidarcy permeability. Unconventional 
wells producing from formations categorized in two or more types are 
considered shale for a combination of ``shale and coal'', ``shale and 
other tight'', or ``shale, coal and other tight''; and are considered 
as coal for combinations of ``coal and other tight''.
    Transmission-Distribution (TD) transfer station. EPA is proposing 
to add a definition for Transmission Distribution (TD) transfer station 
to define what was previously termed ``custody transfer'' in the final 
rule. It was not EPA's intent for the term ``custody transfer'' to be 
defined in the context of ownership of gas transfer. EPA believes the 
new definition may be universally applied to designate which 
``metering-regulating stations'' are classified as ``transmission-
distribution transfer stations.'' All covered stations in the 
distribution segment will be collectively referred to as ``metering-
regulation stations'' but the subset that require leak detection are 
``transmission-distribution transfer stations.'' EPA was notified of 
concerns from industry that defining a

[[Page 56036]]

transmission distribution transfer station without a threshold would 
include numerous small TD transfer stations that would otherwise not 
have been required to perform leak surveys. EPA has not included any 
thresholds in the proposal but we are taking comment on what an 
appropriate threshold would be to exclude these smaller transfer 
stations. Such a threshold should exempt stations with low throughputs 
or low emissions. Any threshold should be readily verifiable and be 
readily applied to all stations. Potential options for a threshold 
include using the inlet pressure, the design or actual flow rate of the 
station, or other parameters directly related to the emissions from the 
station. Any suggested changes should include a discussion of how many 
stations would be exempted from leak detection and how many would still 
require leak detection. Such an exemption would not preclude a station 
from reporting, it would only mean that leak detection is not required 
at that station. The stations that fall below the select threshold 
would still be included for evaluation against the 
25,000mtCO2e threshold through the application of an 
emissions factor. Natural gas distribution facilities that do not have 
any TD transfer stations above the threshold, would use a factor to 
determine their emissions and compare those emissions against the 
25,000 mtCO2e threshold.
    Transmission Pipeline. We are proposing to add a definition for 
transmission pipeline. Transmission pipelines are clearly designated as 
such by the Federal Energy Regulatory Commission for interstate 
transmission pipelines, individual States for intrastate transmission 
pipelines, and the Hinshaw exemption under the Natural Gas Act for 
Hinshaw transmission pipelines. We propose to use this existing 
mechanism to clearly demarcate transmission pipelines from distribution 
and gathering pipelines. Finally, we believe that equipment located on 
designated transmission pipelines that are subject to monitoring under 
subpart W are easily identifiable by facility owners or operators.
    Tubing Systems. Based on a question received in the early phases of 
implementation, we are proposing to clarify that the exclusion for 
piping equal to or less than one half inch diameter applies to the 
nominal pipe size (NPS).
    Vertical Well. With the change from field level reporting to sub-
basin category, EPA is proposing to add a distinction for calculating 
emissions from horizontal wells and vertical wells. EPA proposes that a 
vertical well means a well bore that is primarily vertical but has some 
unintentional deviation or one or more intentional deviations to enter 
one or more subsurface targets that are off-set horizontally from the 
surface location, intercepting the targets either vertically or at an 
angle.
    Well Testing Venting and Flaring. We are proposing to clarify that 
well testing venting and flaring means venting and/or flaring of 
natural gas at the time the production rate of a well is determined 
(i.e., the well testing) through a choke (an orifice restriction). If 
well testing is conducted immediately after well completion or workover 
we are proposing to clarify that it is considered part of the well 
completion or workover.

III. Statutory and Executive Order Review

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 proposes to simplify the existing reporting 
methodologies in subpart W and clarify monitoring methodologies and 
data reporting requirements. 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. In addition, while the proposed 
modification to one of the monitoring methodologies is not expected to 
increase compliance cost, it would require the reporting of information 
not contained in the information collection requirements to 40 CFR 98 
subpart W. Therefore, the proposed amendments to the information 
collection requirements have been submitted for approval to the Office 
of Management and Budget (OMB) under the Paperwork Reduction Act, 44 
U.S.C. 3501 et seq. The Information Collection Request (ICR) document 
has been assigned EPA ICR number 2376.03.
    The proposed amendments to subpart I would carry out the Agency's 
intent to require reporting of emissions of all fluorocarbons used as 
heat transfer fluids in the electronics manufacturing industry. This 
was the intent of the subpart I reporting requirements for HTFs 
finalized in December 2010 (75 FR 74774), and this intent was reflected 
in the Information Collection Request (ICR) prepared during that 
rulemaking. Thus, the proposed amendments will not increase EPA or 
industry burden beyond that estimated in the ICR.
    The Office of Management and Budget (OMB) has previously approved 
the information collection requirements contained in the existing 
regulations, 40 CFR 98 subpart W (75 FR 74458), and 40 CFR part 98 
subpart I (75 FR 74774), under the provisions of the Paperwork 
Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB control 
number 2060-0651 and 2060-0650, respectively. The OMB control numbers 
for EPA's regulations in 40 CFR are listed in 40 CFR part 9.

C. Regulatory Flexibility Act (RFA)

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements under the Administrative 
Procedure Act or any other statute unless the agency certifies that the 
rule will not have a significant economic impact on a substantial 
number of small entities. Small entities include small businesses, 
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of this proposed rule on 
small entities, small entity is defined as: (1) A small business as 
defined by the Small Business Administration's (SBA) regulations at 13 
CFR 121.201; (2) a small governmental jurisdiction that is a government 
of a city, county, town, school district or special district with a 
population of less than 50,000; and (3) a small organization that is 
any not-for-profit enterprise which is independently owned and operated 
and is not dominant in its field.
    After considering the economic impacts of today's proposed rule on 
small entities, I certify that this action will not have a significant 
economic impact on a substantial number of small entities. In 
determining whether a rule has a significant economic impact on a 
substantial number of small entities, the impact of concern is any 
significant adverse economic impact on small entities, since the 
primary purpose of the regulatory flexibility analyses is to identify 
and address regulatory alternatives ``which minimize any significant 
economic impact of the rule on small entities'' 5 U.S.C. 603 and 604. 
Thus, an agency may certify that a rule will not have a significant 
economic impact on a substantial number of small entities if the rule 
relieves regulatory burden, or otherwise has a positive

[[Page 56037]]

economic effect on all of the small entities subject to the rule.
    This action includes proposed amendments to provisions in those 
rules that could result in reduced burden on reporters. In some cases, 
EPA is proposing to increase flexibility in the selection of methods 
use for calculating GHG's, and is also proposing to revise certain 
methods that may result in greater conformance to current industry 
practices. In addition, in this action, EPA is proposing to revise 
specific provisions to provide clarity on what is to be reported. 
Further, in this action, EPA is also proposing amendments to clarify 
the Agency's intent. These proposed revisions could overall reduce 
burden on reporters while maintaining the data quality of the 
information being reported to EPA. As part of the process of 
finalization of the subpart W and subpart I rules, EPA undertook 
specific steps to evaluate the effect of those final rules on small 
entities. Based on the proposed amendments to the subpart W and subpart 
I provisions, burden will stay the same or decrease, therefore EPA's 
determination finding of no significant economic impact on a 
substantial number of small entities has not changed.

D. Unfunded Mandates Reform Act (UMRA)

    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.
    This action is also not subject to the requirements of section 203 
of UMRA because it contains no regulatory requirements that might 
significantly or uniquely affect small governments. Further, 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.

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.
    Few, if any, State or local government facilities would be affected 
by the provisions in this proposed rule. 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.
    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). During the 
finalization of subpart W and subpart I, EPA undertook the necessary 
steps to determine the impact of those rules on tribal entities and 
provided supporting documentation demonstrating the results of the 
Agency's analyses. The proposed rule amendments in this action do not 
impose any significant changes to the current reporting requirements 
contained in 40 CFR part 98 subpart W and 40 CFR part 98 subpart I. And 
in several cases, the proposed amendments to the reporting requirements 
would potentially reduce the reporting burden. Thus, Executive Order 
13175 does not apply to this action.
    Although Executive Order 13175 does not apply to this action, EPA 
consulted tribal officials during the development of the original 
actions. A summary of the concerns raised during the consultation and 
EPA's response to those concerns is provided in Sections VIII.E and 
VIII.F of the preamble to the 2009 final rule and Section IV.F of the 
preamble to the 2010 final rule for subpart W (75 FR 74485). EPA 
specifically solicits additional comment on this proposed action from 
tribal officials.

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

    EPA interprets 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 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, 12(d) (15 U.S.C. 272 note) 
directs EPA to use voluntary consensus standards in its regulatory 
activities unless to do so would be inconsistent with applicable law or 
otherwise impractical. Voluntary consensus standards are technical 
standards (e.g., materials specifications, test methods, sampling 
procedures, and business practices) that are developed or adopted by 
voluntary consensus standards bodies. NTTAA directs EPA to provide 
Congress, through OMB, explanations when the Agency decides not to use 
available and applicable voluntary consensus standards.
    This 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.

[[Page 56038]]

List of Subjects in 40 CFR Part 98

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

    Dated: August 19, 2011.
Lisa P. Jackson,
Administrator.

    For the reasons stated in the preamble, 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.

Subpart A--[Amended]

    2. Section 98.1 is amended by adding paragraph (c) to read as 
follows:


Sec.  98.1  Purpose and scope.

* * * * *
    (c) For facilities required to report under onshore petroleum and 
natural gas production under subpart W of this part, the terms Owner 
and Operator used in subpart A have the same definition as Onshore 
petroleum and natural gas production owner or operator, as defined in 
Sec.  98.238 of this part.
    3. Section 98.6 is amended by revising the definitions for 
``Continuous bleed'' and ``Intermittent bleed pneumatic devices'' to 
read as follows:


Sec.  98.6  Definitions.

* * * * *
    Continuous bleed means a continuous flow of pneumatic supply gas to 
the process control device (e.g., level control, temperature control, 
pressure control) where the supply gas pressure is modulated by the 
process condition, and then flows to the valve controller where the 
signal is compared with the process set-point to adjust gas pressure in 
the valve actuator.
* * * * *
    Intermittent bleed pneumatic devices mean automated flow control 
devices powered by pressurized natural gas and used for automatically 
maintaining a process condition such as liquid level, pressure, delta-
pressure, and temperature. These are snap-acting or throttling devices 
that discharge all or a portion of the full volume of the actuator 
intermittently when control action is necessary, but do not bleed 
continuously.
* * * * *
    4. Section 98.7 is amended by removing paragraph (q).

Subpart I--[Amended]

    5. Section 98.90 is amended by revising paragraph (a)(5) to read as 
follows:


Sec.  98.90  Definition of the source category.

    (a) * * *
    (5) Any electronics manufacturing production process in which 
fluorinated heat transfer fluids are used to cool process equipment, to 
control temperature during device testing, to clean substrate surfaces 
and other parts, and for soldering (e.g., vapor phase reflow).
    6. Section 98.92 is amended by revising paragraph (a) introductory 
text and paragraph (a)(5) to read as follows:


Sec.  98.92  GHGs to report.

    (a) You must report emissions of fluorinated GHGs (as defined in 
Sec.  98.6), N2O, and fluorinated heat transfer fluids (as 
defined in Sec.  98.98). The fluorinated GHGs and fluorinated heat 
transfer fluids that are emitted from electronics manufacturing 
production processes include, but are not limited to, those listed in 
Table I-2 to this subpart. You must individually report, as 
appropriate:
* * * * *
    (5) Emissions of fluorinated heat transfer fluids.
* * * * *
    7. Section 98.93 is amended by revising paragraph (h) introductory 
text and the definition of ``EHi'' in Equation I-16 to read 
as follows.


Sec.  98.93  Calculating GHG Emissions.

* * * * *
    (h) If you use fluorinated heat transfer fluids, you must report 
the annual emissions of fluorinated heat transfer fluids using the mass 
balance approach described in Equation I-16 of this subpart.
* * * * *
EHi = Emissions of fluorinated heat transfer fluids i, 
(metric tons/year).
* * * * *
    8. Section 98.94 is amended by revising paragraph (h) introductory 
text to read as follows:


Sec.  98.94  Monitoring and QA/QC requirements.

* * * * *
    (h) You must adhere to the QA/QC procedures of this paragraph (h) 
when calculating annual gas consumption for each fluorinated GHG and 
N2O used at your facility and emissions from the use of 
fluorinated heat transfer fluids.
* * * * *
    9. Section 98.96 is amended by revising paragraph (r) to read as 
follows:


Sec.  98.96  Data Reporting requirements.

* * * * *
    (r) For heat transfer fluid emissions, inputs to the heat transfer 
fluid mass balance equation, Equation I-16 of this subpart, for each 
fluorinated heat transfer fluid used.
* * * * *
    10. Section 98.98 by removing the definition of ``Heat transfer 
fluids'' and adding the definition of ``Fluorinated heat transfer 
fluids'' in alphabetical order to read as follows:


Sec.  98.98  Definitions.

* * * * *
    Fluorinated heat transfer fluids means fluorinated GHGs used for 
temperature control, device testing, cleaning substrate surfaces and 
other parts, and soldering in certain types of electronics 
manufacturing production processes. For fluorinated heat transfer 
fluids under this subpart I, the lower vapor pressure limit of 1 mm of 
Hg in absolute at 25 degrees C in the definition of Fluorinated 
greenhouse gas in 40 CFR 98.6 shall not apply. Fluorinated heat 
transfer fluids used in the electronics manufacturing sector include, 
but are not limited to, perfluoropolyethers, perfluoroalkanes, 
perfluoroethers, tertiary perfluoroamines, and perfluorocyclic ethers.
* * * * *
    11. Table I-2 to Subpart I is amended by revising the title and the 
second column heading to read as follows:

   Table I-2 to Subpart I of Part 98--Examples of Fluorinated GHGs and
    Fluorinated Heat Transfer Fluids Used by the Electronics Industry
------------------------------------------------------------------------
                                      Fluorinated GHGs and fluorinated
           Product type               heat transfer fluids used during
                                                 manufacture
------------------------------------------------------------------------
Electronics.......................  CF4, C2F6, C3F8, c-C4F8, c-C4F8O,
                                     C4F6, C5F8, CHF3, CH2F2, NF3, SF6,
                                     and HTFs (CF3-(O-CF(CF3)-CF2)n-(O-
                                     CF2)m-O-CF3, CnF2n+2,
                                     CnF2n+1(O)CmF2m+1, CnF2nO,
                                     (CnF2n+1)3N).
------------------------------------------------------------------------


[[Page 56039]]

Subpart W--[Amended]

    12. Section 98.230 is amended by revising paragraphs (a)(2) through 
(a)(4), and (a)(8) to read as follows:


Sec.  98.230  Definition of the source category.

    (a) * * *
    (2) Onshore petroleum and natural gas production. Onshore petroleum 
and natural gas production means all equipment on a single well-pad or 
associated with a single well-pad (including but not limited to 
compressors, generators, dehydrators, storage vessels, and portable 
non-self-propelled equipment which includes well drilling and 
completion equipment, workover equipment, gravity separation equipment, 
auxiliary non-transportation-related equipment, and leased, rented or 
contracted equipment) used in the production, extraction, recovery, 
lifting, stabilization, separation or treating of petroleum and/or 
natural gas (including condensate). This equipment also includes 
associated storage or measurement vessels and all enhanced oil recovery 
(EOR) operations using CO2 or natural gas injection, and all 
petroleum and natural gas production equipment located on islands, 
artificial islands, or structures connected by a causeway to land, an 
island, or an artificial island.
    (3) Onshore natural gas processing. Natural gas processing means 
the separation of natural gas liquids (NGLs) or non-methane gases from 
produced natural gas, or the separation of NGLs into one or more 
component mixtures. Separation includes one or more of the following: 
Forced extraction of natural gas liquids, sulfur and carbon dioxide 
removal, fractionation of NGLs, or the capture of CO2 
separated from natural gas streams. This segment also includes all 
residue gas compression equipment owned or operated by the natural gas 
processing plant. This industry segment includes processing plants that 
fractionate gas liquids, and processing plants that do not fractionate 
gas liquids but have an annual average throughput of 25 MMscf per day 
or greater.
    (4) Onshore natural gas transmission compression. Onshore natural 
gas transmission compression means any stationary combination of 
compressors that move natural gas from production fields, natural gas 
processing plants, or other transmission compressors through 
transmission pipelines to natural gas distribution pipelines, LNG 
storage facilities, or into underground storage. In addition, a 
transmission compressor station includes equipment for liquids 
separation, and tanks for the storage of water and hydrocarbon liquids. 
Residue (sales) gas compression that is part of onshore natural gas 
processing plants are included in the onshore natural gas processing 
segment and are excluded from this segment.
* * * * *
    (8) Natural gas distribution. Natural gas distribution means the 
distribution pipelines and metering and regulating equipment at 
metering-regulating stations that are operated by a Local Distribution 
Company (LDC) within a single state that is regulated as a separate 
operating company by a public utility commission or that is operated as 
an independent municipally-owned distribution system. This segment also 
excludes customer meters and regulators, infrastructure, and pipelines 
(both interstate and intrastate) delivering natural gas directly to 
major industrial users and farm taps upstream of the local distribution 
company inlet.
* * * * *
    13. Section 98.232 is amended by:
    a. Revising paragraph (c) introductory text and paragraph (c)(22).
    b. Revising paragraph (e) introductory text.
    c. Revising paragraph (f) introductory text.
    d. Revising paragraph (g) introductory text.
    e. Revising paragraph (h) introductory text.
    f. Revising paragraph (i) introductory text and paragraph (i)(1).
    g. Redesignating paragraphs (i)(2) through (i)(6) as paragraphs 
(i)(3) through (i)(7), respectively.
    h. Revising newly designated paragraphs (i)(3) and (i)(4).
    i. Adding new paragraph (i)(2).
    j. Removing and reserving paragraph (j).
    k. Revising paragraph (k).
    The revisions read as follows:


Sec.  98.232  GHGs to report.

* * * * *
    (c) For an onshore petroleum and natural gas production facility, 
report CO2, CH4, and N2O emissions 
from only the following source types on a single well-pad or associated 
with a single well-pad:
* * * * *
    (22) You must use the methods in Sec.  98.233(z) and report under 
this subpart the emissions of CO2, CH4, and 
N2O from stationary or portable fuel combustion equipment 
that cannot move on roadways under its own power and drive train, and 
that is located at an onshore petroleum and natural gas production 
facility as defined in Sec.  98.238. Stationary or portable equipment 
are the following equipment, which are integral to the extraction, 
processing, or movement of oil or natural gas: well drilling and 
completion equipment, workover equipment, natural gas dehydrators, 
natural gas compressors, electrical generators, steam boilers, and 
process heaters.
* * * * *
    (e) For onshore natural gas transmission compression, report 
CO2, CH4, and N2O emissions from the 
following sources:
* * * * *
    (f) For underground natural gas storage, report CO2, 
CH4, and N2O emissions from the following 
sources:
* * * * *
    (g) For LNG storage, report CO2, CH4, and 
N2O emissions from the following sources:
* * * * *
    (h) LNG import and export equipment, report CO2, 
CH4, and N2O emissions from the following 
sources:
* * * * *
    (i) For natural gas distribution, report CO2, 
CH4, and N2O emissions from the following 
sources:
    (1) Meters, regulators, and associated equipment at above grade 
transmission-distribution transfer stations, including equipment leaks 
from connectors, block valves, control valves, pressure relief valves, 
orifice meters, regulators, and open ended lines.
    (2) Equipment leaks from vaults at below grade transmission-
distribution transfer stations.
    (3) Meters, regulators, and associated equipment at above grade 
metering-regulating station.
    (4) Equipment leaks from vaults at below grade metering-regulating 
stations.
* * * * *
    (j) [Reserved].
    (k) Report under subpart C of this part (General Stationary Fuel 
Combustion Sources) the emissions of CO2, CH4, 
and N2O from each stationary fuel combustion unit by 
following the requirements of subpart C except for facilities under 
onshore petroleum and natural gas production and natural gas 
distribution. Onshore petroleum and natural gas production facilities 
must report stationary and portable combustion emissions as specified 
in paragraph (c) of this section. Natural gas distribution facilities 
must report stationary combustion emissions as specified in paragraph 
(i) of this section.
    14. Section 98.233 is amended by:
    a. In paragraph (a), revising Equation W-1 and the definitions of 
``Count'' and

[[Page 56040]]

``GHGi'' in Equation W-1; and adding the definition of ``T'' 
in Equation W-1.
    b. Adding paragraph (a)(3).
    c. In paragraph (c), revising Equation W-2 and the definition of 
``GHGi''; and adding the definition of ``T'' in Equation W-
2.
    d. Revising paragraphs (d) introductory text and (d)(1).
    e. In paragraph (d)(3), revising Equation W-4 and removing the 
definition of ``[alpha]'' in Equation W-4.
    f. Revising paragraph (e)(1)(vii).
    g. Revising the definition of ``1000'' in Equation W-5 of paragraph 
(e)(2).
    h. Revising paragraph (e)(6).
    i. Revising paragraphs (f) introductory text, (f)(1) introductory 
text, and the definitions of Equation W-7 in paragraph (f)(1).
    j. Revising paragraphs (f)(1)(i)(A) through (f)(1)(i)(C).
    k. In paragraph (f)(2), revising Equation W-8 and the definitions 
of Equation W-8.
    l. Removing paragraphs (f)(2)(i) and (f)(2)(ii).
    m. In paragraph (f)(3), revising Equation W-9 and the definitions 
of Equation W-9.
    n. Removing paragraphs (f)(3)(i) and (f)(3)(ii).
    o. In paragraph (g), revising Equation W-10 and the definitions of 
Equation W-10.
    p. Revising introductory texts for paragraphs (g)(1) and (g)(1)(i).
    q. Removing paragraphs (g)(1)(i)(A) through (g)(1)(i)(D).
    r. In paragraph (g)(1)(ii), revising paragraph (g)(1)(ii) 
introductory text; redesignating Equation W-11 as Equation W-11A and 
Equation W-12 as Equation W-11B respectively; and adding Equation W-
11C.
    s. Redesignating paragraphs (g)(1)(ii)(A) through (g)(1)(ii)(B) as 
paragraphs (g)(1)(iii) through (g)(1)(v) and revising new paragraphs 
(g)(1)(iii) through (g)(1)(v).
    t. Removing paragraph (g)(1)(ii)(D).
    u. Revising introductory texts for paragraphs (g)(3) and (g)(5).
    v. In paragraph (h), revising paragraph (h) introductory text and 
the definitions of ``Nwo'', ``f'', ``Vp'' and 
``Tp'' in Equation W-13.
    w. Revising paragraph (i) introductory text and paragraphs (i)(1) 
and (i)(2).
    x. In paragraph (i)(3), revising paragraph (i)(3) introductory 
text; redesignating Equation W-14 as Equation W-14A; revising the 
definition of ``N'' in newly redesignated Equation W-14A; and adding 
Equation W-14B.
    y. Revising paragraph (i)(5).
    z. Revising paragraph (j)(1)(vii)(B), (j)(1)(vii)(C), and 
(j)(3)(i).
    aa. Revising paragraphs (k)(1) and (k)(2)(i).
    bb. Revising paragraph (m)(1).
    cc. Revising paragraph (n)(2)(ii) and (n)(2)(iii), and in paragraph 
(n)(4), revising equation W-21 and the definition for 
``Yj''.
    dd. Redesignating paragraph (n)(9) as paragraph (n)(10) and adding 
new paragraphs (n)(9) and (n)(11).
    ee. In paragraph (o)(6), revising the definition of 
``MTm'' in Equation W-24.
    ff. In paragraph (p)(7)(i), revising the definition of 
``MTm'' in Equation W-28.
    gg. In paragraph (q), revising equation W-30 and the definitions 
for ``x'', ``EF'', ``GHGi'', ``Tp'', and revising 
paragraph (q)(8).
    hh. In paragraph (r), revising the definitions of 
``Counts'', ``EFs'', and ``GHGi'' in 
Equation W-31.
    ii. Revising paragraphs (r)(2)(i)(A), (r)(6)(i), (r)(6)(ii) 
introductory text, Equation W-32, and the definitions of Equation W-32.
    jj. Revising introductory texts for paragraphs (t), (t)(1), and 
(t)(2).
    kk. Revising paragraph (u) introductory text and paragraph (u)(2).
    ll. In paragraph (v), revising paragraph (v) introductory text and 
the definitions of ``Masss,i'', ``Es,i'', and 
``[rho]i'' in Equation W-36.
    mm. Revising introductory texts for paragraphs (z), (z)(1), (z)(2), 
(z)(2)(i), and (z)(2)(ii).
    nn. Adding paragraphs (z)(1)(i) and (z)(1)(ii).
    The revisions read as follows:


Sec.  98.233  Calculating GHG emissions.

    (a) * * *
    [GRAPHIC] [TIFF OMITTED] TP09SE11.000
    
* * * * *
Count = Total number of continuous high bleed, continuous low bleed, 
or intermittent bleed natural gas pneumatic devices of each type as 
determined in paragraph (a)(1) and (a)(2) of this section.
* * * * *
GHGi = For onshore petroleum and natural gas production 
facilities, onshore natural gas transmission compression, and 
underground natural gas storage, concentration of GHGi, 
CH4, or CO2, in natural gas as defined in 
paragraph (u)(2)(i) of this section.
* * * * *
T = Total number of hours in the operating year the devices were 
operational.
* * * * *
    (3) For all industry segments, determine the type of pneumatic 
device using engineering estimates based on best available information.
* * * * *
    (c) * * *
    [GRAPHIC] [TIFF OMITTED] TP09SE11.001
    
* * * * *
GHGi = Concentration of GHGi, CH4, 
or CO2, in produced natural gas as defined in paragraph 
(u)(2)(i) of this section.
* * * * *
T = Total number of hours in the operating year the pumps were 
operational.
* * * * *
    (d) Acid gas removal (AGR) vents. For AGR vent (including processes 
such as amine, membrane, molecular sieve or other absorbents and 
adsorbents), calculate emissions for CO2 only (not 
CH4) vented directly to the atmosphere or through a flare, 
engine (e.g., permeate from a membrane or de-adsorbed gas from a 
pressure swing adsorber used as fuel supplement), or sulfur recovery 
plant using any of the calculation methodologies described in paragraph 
(d) of this section, as applicable.
* * * * *
    (1) Calculation Methodology 1. If you operate and maintain a CEMS 
that has both a CO2 concentration monitor and volumetric 
flow rate monitor, you must calculate CO2 emissions under 
this subpart by following the Tier 4 Calculation Methodology and all 
associated calculation, quality assurance, reporting, and recordkeeping 
requirements for Tier 4 in subpart C of this part (General Stationary 
Fuel Combustion Sources). If a CO2 concentration monitor and 
volumetric flow rate monitor are not available, you

[[Page 56041]]

may elect to install a CO2 concentration monitor and a 
volumetric flow rate monitor that comply with all of the requirements 
specified for the Tier 4 Calculation Methodology in subpart C of this 
part (General Stationary Fuel Combustion). The calculation and 
reporting of CH4 and N2O emissions is not 
required as part of the Tier 4 requirements for AGRs.
* * * * *
    (3) * * *
    [GRAPHIC] [TIFF OMITTED] TP09SE11.002
    
* * * * *
    (e) * * *
    (1) * * *
    (vii) Use of stripping gas.
* * * * *
    (2)
* * * * *
1000 = Conversion of EFi in thousand standard cubic feet to 
cubic feet.
* * * * *
    (6) For glycol dehydrators, both CH4 and CO2 
mass emissions shall be calculated from volumetric GHGi 
emissions using calculations in paragraph (v) of this section. For 
dehydrators that use desiccant, both CH4 and CO2 
volumetric and mass emissions shall be calculated from volumetric 
natural gas emissions using calculations in paragraphs (u) and (v) of 
this section.
* * * * *
    (f) Well venting for liquids unloadings. Calculate CO2 
and CH4 emissions from well venting for liquids unloading 
using one of the calculation methodologies described in paragraphs 
(f)(1), (f)(2), or (f)(3) of this section.
    (1) Calculation Methodology 1. For one well of each unique well 
tubing diameter grouping and pressure grouping in each sub-basin 
category (see Sec.  98.238 for the definitions of tubing diameter 
grouping, pressure grouping, and sub-basin category), where gas wells 
are vented to the atmosphere to expel liquids accumulated in the 
tubing, a recording flow meter shall be installed on the vent line used 
to vent gas from the well (e.g., on the vent line off the wellhead 
separator or atmospheric storage tank) according to methods set forth 
in Sec.  98.234(b). Calculate emissions from well venting for liquids 
unloading using Equation W-7 of this section.
* * * * *
Ea,n = Annual natural gas emissions for wells of the same 
tubing diameter grouping and pressure grouping at actual conditions 
in cubic feet.
Th,t = Cumulative amount of time in hours of venting from 
all wells of the same tubing diameter grouping p and pressure 
grouping q during the year.
FRh,t = Average flow rate in cubic feet per hour of a 
measured well venting for the duration of the liquids unloading, 
under actual conditions as determined in paragraph (f)(1)(i) of this 
section.
h = Total number of different tubing diameter groupings.
p = Tubing diameter grouping 1 through h.
t = Total number of pressure groupings.
q = Pressure grouping 1 through t.
* * * * *
    (i) * * *

    (A) The average flow rate per hour of venting is calculated for 
each unique tubing diameter grouping and pressure grouping in each sub-
basin category by dividing the recorded total flow by the recorded time 
(in hours) for a single liquid unloading with venting to the 
atmosphere.
    (B) This average flow rate per hour is applied to all wells in the 
same pressure grouping that have the same tubing diameter grouping, for 
the number of hours of venting these wells.
    (C) A new average flow rate is calculated every other calendar year 
for each reporting sub-basin category starting the first calendar year 
of data collection. For a new producing sub-basin category, an average 
flow rate is calculated beginning in the first year of production.
    (2) * * *
    [GRAPHIC] [TIFF OMITTED] TP09SE11.003
    
Where:

Es,n = Annual natural gas emissions at standard 
conditions, in cubic feet/year.
W = Total 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).
CDP = Casing diameter for each well, p, in inches.
WDP = Well depth from the lowest packer to the bottom of 
the well, in feet.
SPP = Shut-in pressure for each well, p, in pounds per 
square inch atmosphere (psia).
VP = Number of vents per year per well, p.
SFRP = Average sales flow rate of gas well, p, at 
standard conditions in cubic feet per hour. Use Equation W-33 to 
calculate the sales flow rate at standard conditions.
HRQ,PW = Hours that each well,p, was left open to the 
atmosphere during unloading, q.
1.0 = Hours for average well to blowdown casing volume at shut-in 
pressure.
ZQ,P = If HRQ,P is less than 1.0 then 
ZQ,P is equal to 0. If HRQ,P is greater than 
or equal to 1.0 then ZQ,P is equal to 1.
    (3) * * *
    [GRAPHIC] [TIFF OMITTED] TP09SE11.004
    
Where:

Es,n = Annual natural gas emissions at standard 
conditions, in cubic feet/year.
W = Total 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).

[[Page 56042]]

TDP = Tubing diameter for each well, p,in inches.
WDP = Tubing depth to plunger bumper for each well, p, in 
feet.
SPP = Sales line pressure for each well, p, in pounds per 
square inch atmospheric (psia).
VP = Number of vents per year for each well, p.
SFRP = Average sales flow rate of each gas well, p, at 
standard conditions in cubic feet per hour. Use Equation W-33 to 
calculate the sales flow rate at standard conditions.
HRQ,P = Hours that each well, p, was left open to the 
atmosphere during each unloading, q.
0.5 = Hours for average well to blowdown tubing volume at sales line 
pressure.
ZQ,P = If HRQ,P is less than 0.5 then 
ZQ,P is equal to 0. If HRQ,P is greater than 
or equal to 0.5 then ZQ,P is equal to 1.
* * * * *
    (g) * * *
    [GRAPHIC] [TIFF OMITTED] TP09SE11.005
    

Where:

Es,n = Annual volumetric total gas emissions in cubic 
feet at standard conditions from gas well venting during completions 
or workovers following hydraulic fracturing for each sub-basin and 
well type combination.
Tp = Cumulative amount of time in hours of each well (p) 
completion or workover venting in a sub-basin and well type 
combination during the reporting year.
FRM = Venting to 30-day production ratio from Equation W-12.
PRp = First 30-day average production flow rate in 
standard cubic feet per hour of each well (p), under actual 
conditions, converted to standard conditions, as required in 
paragraph (g)(1) of this section.
EnFp = Volume of CO2 or N2 injected 
gas in cubic feet at standard conditions that was injected into the 
reservoir during an energized fracture job for each well (p). If the 
fracture process did not inject gas into the reservoir, then EnF is 
0. If injected gas is CO2, then EnF is 0.
SGp = Volume of natural gas in cubic feet at standard 
conditions that was recovered into a sales pipeline for well p as 
per paragraph (g)(3) of this section. If no gas was recovered for 
sales, SG is 0.
W = Total number of wells completed or worked over using hydraulic 
fracturing in a sub-basin and well type combination.

    (1) The average flow rate for gas well venting to the atmosphere or 
to a flare during well completions and workovers from hydraulic 
fracturing shall be determined using measurement(s) from either of the 
calculation methodologies described in this paragraph (g)(1) of this 
section. The number of measurements shall be determined as follows: One 
measurement for less than or equal to 25 completions/workovers; two 
measurements for 26 to 50 completions/workovers; three measurements for 
51 to 100 completions/workovers; four measurements for 101 to 250 
completions/workovers; and five measurements for greater than 250 
completions/workovers.
    (i) Calculation Methodology 1. For well completion(s) in each gas 
producing sub-basin category and well type (horizontal or vertical) 
combination and for one well workover(s) in each gas producing sub-
basin category and well type (horizontal or vertical) combination, a 
recording flow meter (digital or analog) shall be installed on the vent 
line, ahead of a flare if used, to measure the backflow venting 
according to methods set forth in Sec.  98.234(b).
    (ii) Calculation Methodology 2. For one horizontal well completion 
and one vertical well completion in each gas producing sub-basin 
category and for one well horizontal workover and one vertical well 
workover in each gas producing sub-basin category, record the well 
flowing pressure upstream (and downstream in subsonic flow) of a well 
choke according to methods set forth in Sec.  98.234(b) to calculate 
the intermittent well flow rate of gas during venting to the atmosphere 
or a flare. Calculate emissions using Equation W-11A of this section 
for subsonic flow or Equation W-11B of this section for sonic flow. Use 
Equation W-11C of this section to determine whether flow is sonic or 
subsonic. If the value of R in Equation W-11C is greater than or equal 
to 2, then flow is sonic; otherwise, flow is subsonic:
[GRAPHIC] [TIFF OMITTED] TP09SE11.006


Where:

FR = Average flow rate in cubic feet per hour, under subsonic flow 
conditions.
A = Cross sectional area of orifice (m2).
P1 = Upstream pressure (psia).
Tu = Upstream temperature (degrees Kelvin).
P2 = Downstream pressure (psia).
3430 = Constant with units of m2/(sec2 * K).
1.27*105 = Conversion from m3/second to ft3/
hour.

[GRAPHIC] [TIFF OMITTED] TP09SE11.007

Where:

FR = Average flow rate in cubic feet per hour, under sonic flow 
conditions.
A = Cross sectional area of orifice (m2).
Tu = Upstream temperature (degrees Kelvin).
187.08 = Constant with units of m2/(sec2 * K).
1.27*105 = Conversion from m3/second to ft3/
hour.

[GRAPHIC] [TIFF OMITTED] TP09SE11.008


[[Page 56043]]


Where:

R = Pressure ratio
P1 = Pressure upstream of the restriction orifice in 
pounds per square inch absolute.
P2 = Pressure downstream of the restriction orifice in 
pounds per square inch absolute.
    (iii) The emissions to 30-day production ratio is calculated 
using Equation W-12 of this section.

[GRAPHIC] [TIFF OMITTED] TP09SE11.009

Where:

FRM = Emissions to 30-day production ratio.
FRp = Measured flow rate from Calculation Methodology 1 
or estimated flow rate from Calculation Methodology 2 in standard 
cubic feet per hour for well(s) p for each sub-basin and well type 
(horizontal or vertical) combination.
PRp = First 30-day production rate in standard cubic feet 
per hour for each well p that was measured in the sub-basin and well 
type combination.
W = Number of wells completed or worked over using hydraulic 
fracturing in a sub-basin and well type formation.

    (iv) The flow rates for horizontal and vertical wells are applied 
to all horizontal and vertical well completions in the gas producing 
sub-basin and well type combination and to all horizontal and vertical 
well workovers, respectively, in the gas producing sub-basin and well 
type combination for the total number of hours of venting of each of 
these wells.
    (v) New flow rates for horizontal and vertical gas well completions 
and horizontal and vertical gas well workovers in each sub-basin 
category shall be calculated once every two years starting in the first 
calendar year of data collection.
    (2) The volume of CO2 or N2 injected into the 
well reservoir during energized hydraulic fractures will be measured 
using an appropriate meter as described in Sec.  98.234(b) or using 
receipts of gas purchases that are used for the energized fracture job.
    (i) Calculate gas volume at standard conditions using calculations 
in paragraph (t) of this section.
    (ii) [Reserved].
    (3) The volume of recovered completion or workover gas sent to a 
sales line will be measured using existing company records. If data 
does not exist on sales gas, then an appropriate meter as described in 
Sec.  98.234(b) may be used.
* * * * *
    (5) Determine if the well completion or workover from hydraulic 
fracturing recovered gas with purpose designed equipment that separates 
saleable gas from the backflow, and sent this gas to a sales line 
(e.g., reduced emissions completions or workovers).
* * * * *
    (h) Gas well venting during completions and workovers without 
hydraulic fracturing. Calculate CH4, CO2 and 
N2O (when flared) emissions from each gas well venting 
during well completions and workovers not involving hydraulic 
fracturing using Equation W-13 of this section:
* * * * *
Nwo = Number of workovers per sub-basin not involving 
hydraulic fracturing in the reporting year.
f = Total number of well completions without hydraulic fracturing in 
a sub-basin category.
Vp = Average daily gas production rate in cubic feet per 
hour for each well completion without hydraulic fracturing, p. 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.
Tp = Time each well completion without hydraulic 
fracturing, p, was venting in hours during the year.

* * * * *
    (i) Blowdown vent stacks. Calculate CO2 and 
CH4 blowdown vent stack emissions from depressurizing 
equipment to reduce system pressure for planned or emergency shutdowns 
or to take equipment out of service for maintenance (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:
    (1) Calculate the total physical volume (including pipelines, 
compressor case or cylinders, manifolds, suction bottles, discharge 
bottles, and vessels) between isolation valves determined by 
engineering estimates based on best available data.
    (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 unique physical volume type (including but not 
limited to compressors, vessels, pipelines, headers, fractionators, and 
tanks). Physical volumes smaller than 50 standard cubic feet are exempt 
from reporting under paragraph (i) of this section.
    (3) Calculate the total annual venting emissions for each equipment 
type using either Equation W-14A or W-14B of this section.
[GRAPHIC] [TIFF OMITTED] TP09SE11.010

Where:

* * * * *
Vv = Total volume of blowndown equipment chambers 
(including pipelines, compressors and vessels) between isolation 
valves in cubic feet.
* * * * *

[[Page 56044]]

[GRAPHIC] [TIFF OMITTED] TP09SE11.011


Where:

Es,n = Annual natural gas venting emissions at standard 
conditions from blowdowns in cubic feet.
N = Number of repetitive blowdowns for each unique volume in 
calendar year.
Vv = Total volume of blowdown equipment chamber 
(including pipelines, compressors and vessels) between isolation 
valves in cubic feet for each blowdown ``i.''
C = Purge factor that is 1 if the equipment is not purged or zero if 
the equipment is purged using non-GHG gases.
Ts = Temperature at standard conditions ([deg]F).
Ta = Temperature at actual conditions in the blowdown 
equipment chamber ([deg]F) for each blowdown ``i''.
Ps = Absolute pressure at standard conditions (psia).
Pa,s,p = Absolute pressure at actual conditions in the 
blowdown equipment chamber (psia) at the start of the blowdown 
``p''.
Pa,e,p = Absolute pressure at actual conditions in the 
blowdown equipment chamber (psia) at the end of the blowdown ``p''; 
0 if blowdown volume is purged using non-GHG gases.
* * * * *

    (5) Calculate total annual venting emissions for all blowdown vent 
stacks by adding all standard volumetric and mass emissions determined 
using Equations W-14A or W-14B and paragraph (i)(4) of this section.
    (j) * * *
    (1) * * *
    (vii) * * *
    (B) If separator oil composition and Reid vapor pressure data are 
available through your previous analysis, select the latest available 
analysis that is representative of produced crude oil or condensate 
from the sub-basin category.
    (C) Analyze a representative sample of separator oil in each sub-
basin category for oil composition and Reid vapor pressure using an 
appropriate standard method published by a consensus-based standards 
organization.
* * * * *
    (3) * * *
    (i) If well production oil and gas compositions are available 
through your previous analysis, select the latest available analysis 
that is representative of produced oil and gas from the sub-basin 
category and assume all of the CH4 and CO2 in 
both oil and gas are emitted from the tank.
* * * * *
    (k) * * *
    (1) Monitor the tank vapor vent stack annually for emissions using 
an optical gas imaging instrument according to methods set forth in 
Sec.  98.234(a)(1) or by directly measuring the tank vent using a flow 
meter, calibrated bag, or high volume sampler according to methods in 
Sec.  98.234(b) through (d) for a duration of 5 minutes. Or you may 
annually monitor leakage through compressor scrubber dump valve(s) into 
the tank using an acoustic leak detection device according to methods 
set forth in Sec.  98.234(a)(5).
    (2) * * *
    (i) Use a meter, such as a turbine meter, calibrated bag, or high 
flow sampler to estimate tank vapor volumes according to methods set 
forth in Sec.  98.234(b) through (d). If you do not have a continuous 
flow measurement device, you may install a flow measuring device on the 
tank vapor vent stack. If the vent is directly measured for five 
minutes under paragraph Sec.  98.233(k)(1) of this section to detect 
continuous leakage, this serves as the measurement.
    (m) * * *
    (1) Determine the GOR of the hydrocarbon production from each well 
whose associated natural gas is vented or flared. If GOR from each well 
is not available, the GOR from a cluster of wells in the same sub-basin 
category shall be used.
* * * * *
    (n) * * *
    (2) * * *
    (ii) For onshore natural gas processing, when the stream going to 
flare is natural gas, use the GHG mole percent in feed natural gas for 
all streams upstream of the de-methanizer or dew point control, and GHG 
mole percent in facility specific residue gas to transmission pipeline 
systems for all emissions sources downstream of the de-methanizer 
overhead or dew point control for onshore natural gas processing 
facilities. For onshore natural gas processing plants that solely 
fractionate a liquid stream, use the GHG mole percent in feed natural 
gas liquid for all streams.
    (iii) For any applicable industry segment, when the stream going to 
the flare is a hydrocarbon product stream, such as methane, ethane, 
propane, butane, pentane-plus and mixed light hydrocarbons, then you 
may use a representative composition from the source for the stream 
determined by engineering calculation based on process knowledge and 
best available data.
* * * * *
    (n) * * *
    [GRAPHIC] [TIFF OMITTED] TP09SE11.012
    

* * * * *
Yj = Mole fraction of gas hydrocarbon constituents j 
(such as methane, ethane, propane, butane, and pentanes-plus)
* * * * *

    (9) If you operate and maintain a CEMS that has both a 
CO2 concentration monitor and volumetric flow rate monitor, 
you must calculate CO2 emissions for the flare by following 
the Tier 4 Calculation Methodology and all associated calculation, 
quality assurance, reporting, and recordkeeping requirements for Tier 4 
in subpart C of this part (General Stationary Fuel Combustion Sources). 
If a CEMS is used to calculate flare stack emissions, the requirements 
specified in paragraphs (n)(1) through (n)(7) are not required. If a 
CO2 concentration monitor and volumetric flow rate monitor 
are not available, you may elect to install a CO2 
concentration monitor and a volumetric flow rate monitor that comply 
with all of the requirements specified for the Tier 4 Calculation 
Methodology in subpart C of this part (General Stationary Fuel 
Combustion).
    (10) The flare emissions determined under paragraph (n) of this 
section must be corrected for flare emissions calculated and reported 
under other paragraphs of this section to avoid double counting of 
these emissions.
    (11) If source types in Sec.  98.233 use Equations W-19 through W-
21 of this section, use estimate of emissions under actual conditions 
for the parameter, Va, in these equations.


[[Page 56045]]


    (o) * * *
    (6) * * *
* * * * *
MTm = Flow Measurements from all centrifugal compressor 
vents in each mode in (o)(1)(i) through (o)(1)(iii) of this section 
in standard cubic feet per hour.
* * * * *
    (p) * * *
    (7) * * *
    (i) * * *
* * * * *
MTm = Meter readings from all reciprocating compressor 
vents in each and mode, m, in standard cubic feet per hour.
* * * * *
    (q) * * *
* * * * *

[GRAPHIC] [TIFF OMITTED] TP09SE11.013


* * * * *
x = Total number of each equipment leak source.
* * * * *
GHGi = For onshore natural gas processing facilities, 
concentration of GHGi, CH4 or CO2, 
in the total hydrocarbon of the feed natural gas; 98.230(a)(4) and 
(a)(5), GHGi equals 0.974 for CH4 and 1.0 x 
10-2 for CO2; for facilities listed in Sec.  
98.230(a)(6) and (a)(7), GHGi equals 1 for CH4 
and 0 for CO2; and for facilities listed in Sec.  
98.230(a)(8), GHGi equals 1 for CH4 and 1.1 x 
10-2 CO2.
Tp = The total time the component, p, was found leaking 
and operational, in hours. If one leak detection survey is 
conducted, assume the component was leaking for the entire calendar 
year. If multiple leak detection surveys are conducted, assume that 
the component found to be leaking has been leaking since the 
previous survey or the beginning of the calendar year. For the last 
leak detection survey in the calendar year, assume that all leaking 
components continue to leak until the end of the calendar year.
* * * * *

    (8) Natural gas distribution facilities for above grade 
transmission-distribution transfer stations, shall use the appropriate 
default leaker emission factors listed in Table W-7 of this subpart for 
equipment leak detected from connectors, block valves, control valves, 
pressure relief valves, orifice meters, regulators, and open ended 
lines. Leak detection at natural gas distribution facilities is only 
required at above grade stations that qualify as transmission-
distribution transfer stations. Below grade transmission-distribution 
transfer stations and metering-regulating stations that do not meet the 
definition of transmission-distribution transfer stations are not 
required to perform component leak detection under this section.
    (r) * * *
* * * * *

Counts = Total number of this type of emission source at 
the facility. For onshore petroleum and natural gas production, 
average component counts are provided by major equipment piece in 
Tables W-1B and Table W-1C of this subpart. Use average component 
counts as appropriate for operations in Eastern and Western U.S., 
according to Table W-1D of this subpart. Underground natural gas 
storage shall count the components listed for population emission 
factors in Table W-4. LNG Storage shall count the number of vapor 
recovery compressors. LNG import and export shall count the number 
of vapor recovery compressors. Natural gas distribution shall count 
the respective component for each emission factor as described in 
paragraph (r)(6) of this section.
EFs = Population emission factor for the specific source, 
as listed in Table W-1A and Tables W-3 through Table W-7 of this 
subpart. Use appropriate population emission factor for operations 
in Eastern and Western U.S., according to Table W-1D of this 
subpart. EF for meter/regulator runs at above grade metering-
regulating stations is determined in Equation W-32 of this section.
    GHGi = For onshore petroleum and natural gas 
production facilities, concentration of GHGi, 
CH4 or CO2, in produced natural gas; for other 
facilities listed in Sec.  98.230(a)(4) and (a)(5), GHGi 
equals 0.952 for CH4 and 1.0 x 10-2 for 
CO2; for facilities listed in Sec.  98.230(a)(6) and 
(a)(7), GHGi equals 1 for CH4 and 0 for 
CO2; and for facilities listed in Sec.  98.230(a)(8), 
GHGi equals 1 for CH4 and 1.1 x 
10-2 CO2.
* * * * *

    (2) * * *
    (i) * * *
    (A) Count all major equipment listed in Table W-1B and Table W-1C 
of this subpart. For meters/piping, use one meters/piping per well-pad.
* * * * *
    (6) * * *
    (i) Below grade metering-regulating stations (including below grade 
T-D transfer stations); distribution mains; and distribution services, 
shall use the appropriate default population emission factors listed in 
Table W-7 of this subpart.
    (ii) Emissions from all above grade metering-regulating stations 
(including above grade TD transfer stations) shall be calculated by 
applying the emission factor calculated in Equation W-32 and the total 
count of meter/regulator runs at all above grade metering-regulating 
stations (inclusive of TD transfer stations) to Equation W-31. The 
facility wide emission factor in Equation W-32 will be calculated by 
using the total volumetric GHG emissions at standard conditions for all 
equipment leak sources calculated in paragraph (q)(8) of this section 
and the count of meter/regulator runs located at above grade 
transmission-distribution transfer stations.
[GRAPHIC] [TIFF OMITTED] TP09SE11.014


Where:
EFi = Facility emission factor for a meter/regulator run 
at above grade metering-regulating for GHGi in cubic feet 
per meter/regulator run per hour.
Es,i = Annual volumetric GHG i emissions, CO2 
or CH4 at standard condition from all equipment leak 
sources at all above grade TD transfer stations, from paragraph (q) 
of this section.
Count = Total number of meter/regulator runs at all TD transfer 
stations.
8760 = Conversion to hourly emissions
* * * * *

    (t) Volumetric emissions. Calculate volumetric emissions at 
standard conditions as specified in paragraphs (t)(1) or (2) of this 
section, with actual pressure and temperature determined by engineering 
estimates based on best available data unless otherwise specified.
    (1) Calculate natural gas volumetric emissions at standard 
conditions using

[[Page 56046]]

actual natural gas emission temperature and pressure, and Equation W-33 
of this section.
* * * * *
    (2) Calculate GHG volumetric emissions at standard conditions using 
actual GHG emissions temperature and pressure, and Equation W-34 of 
this section.
* * * * *
    (u) GHG volumetric emissions. Calculate GHG volumetric emissions at 
standard conditions as specified in paragraphs (u)(1) and (2) of this 
section, with mole fraction of GHGs in the natural gas determined by 
engineering estimate based on best available data unless otherwise 
specified.
* * * * *
    (2) For Equation W-35 of this section, the mole fraction, Mi, shall 
be the annual average mole fraction for each sub-basin category or 
facility, as specified in paragraphs (u)(2)(i) through (vii) of this 
section.
    (i) GHG mole fraction in produced natural gas for onshore petroleum 
and natural gas production facilities. If you have a continuous gas 
composition analyzer for produced natural gas, you must use an annual 
average of these values for determining the mole fraction. If you do 
not have a continuous gas composition analyzer, then you must use an 
annual average gas composition based on available analyses in each of 
the sub-basin categories.
    (ii) GHG mole fraction in feed natural gas for all emissions 
sources upstream of the de-methanizer or dew point control and GHG mole 
fraction in facility specific residue gas to transmission pipeline 
systems for all emissions sources downstream of the de-methanizer 
overhead or dew point control for onshore natural gas processing 
facilities. For onshore natural gas processing plants that solely 
fractionate a liquid stream, use the GHG mole percent in feed natural 
gas liquid for all streams. If you have a continuous gas composition 
analyzer on feed natural gas, you must use these values for determining 
the mole fraction. If you do not have a continuous gas composition 
analyzer, then annual samples must be taken according to methods set 
forth in Sec.  98.234(b).
    (iii) GHG mole fraction in transmission pipeline natural gas that 
passes through the facility for onshore natural gas transmission 
compression facilities. You may use a default 95 percent methane and 1 
percent carbon dioxide fraction for GHG mole fraction in natural gas.
    (iv) GHG mole fraction in natural gas stored in underground natural 
gas storage facilities. You may use a default 95 percent methane and 1 
percent carbon dioxide fraction for GHG mole fraction in natural gas.
    (v) GHG mole fraction in natural gas stored in LNG storage 
facilities. You may use a default 95 percent methane and 1 percent 
carbon dioxide fraction for GHG mole fraction in natural gas.
    (vi) GHG mole fraction in natural gas stored in LNG import and 
export facilities. For export facilities that receive gas from 
transmission pipelines, you may use a default 95 percent methane and 1 
percent carbon dioxide fraction for GHG mole fraction in natural gas.
    (vii) GHG mole fraction in local distribution pipeline natural gas 
that passes through the facility for natural gas distribution 
facilities. You may use a default 95 percent methane and 1 percent 
carbon dioxide fraction for GHG mole fraction in natural gas.
    (v) GHG mass emissions. Calculate GHG mass emissions in carbon 
dioxide equivalent at standard conditions by converting the GHG 
volumetric emissions at standard conditions into mass emissions using 
Equation W-36 of this section.
* * * * *

Masss,i = GHG i (either CH4, CO2, 
or N2O) mass emissions at standard conditions in metric 
tons CO2e.
Es,i = GHG i (either CH4, CO2, or 
N2O) volumetric emissions at standard conditions, in 
cubic feet.
[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:
    (1) If a fuel combusted in the stationary or portable equipment is 
listed in Table C-1 of subpart C of this part, or is a blend containing 
one or more fuels listed in Table C-1, calculate emissions according to 
(z)(1)(i). If the fuel is natural gas and is of pipeline quality 
specification and has a minimum high heat value of 950 Btu per standard 
cubic foot, use the calculation methodology described in (z)(1)(i) and 
you may use the emission factor provided for natural gas as listed in 
Table C-1. If the fuel is natural gas, and is not pipeline quality or 
has a high heat value of less than 950 But per standard cubic feet, 
calculate emissions according to (z)(2). If the fuel is field gas, 
process vent gas, or a blend containing field gas or process vent gas, 
calculate emissions according to (z)(2).
    (i) For fuels listed in Table C-1 or a blend containing one more 
fuels listed in Table C-1, calculate CO2, CH4, 
and N2O emissions according to any Tier listed in subpart C 
of this part. You must follow all applicable calculation requirements 
for that tier listed in 98.33, any monitoring or QA/QC requirements 
listed for that tier in 98.34, any missing data procedures specified in 
98.35, and any recordkeeping requirements specified in 98.37.
    (ii) Emissions from fuel combusted in stationary or portable 
equipment at onshore natural gas and petroleum production facilities 
and at natural gas distribution facilities will be reported according 
to the requirements specified in 98.236(c)(19) and not according to the 
reporting requirements specified in subpart C of this part.
    (2) For fuel combustion units that combust field gas, process vent 
gas, a blend containing field gas or process vent gas, or natural gas 
that is not of pipeline quality or that has a high heat value of less 
than 950 Btu per standard cubic feet, calculate combustion emissions as 
follows:
    (i) You may use company records to determine the volume of fuel 
combusted in the unit during the reporting year.
    (ii) If you have a continuous gas composition analyzer on fuel to 
the combustion unit, you must use these compositions for determining 
the concentration of gas hydrocarbon constituent in the flow of gas to 
the unit. If you do not have a continuous gas composition analyzer on 
gas to the combustion unit, you must use the appropriate gas 
compositions for each stream of hydrocarbons going to the combustion 
unit as specified in paragraph (u)(2)(i) of this section.
    15. Section 98.234 is amended by:
    a. Revising paragraphs (a)(1), (a)(2), and (a)(5).
    b. Removing and reserving paragraph (a)(4).
    c. Revising paragraph (c) introductory text and paragraph (d)(3).


Sec.  98.234  Monitoring and QA/QC requirements.

    (a) * * *
    (1) Optical gas imaging instrument. Use an optical gas imaging 
instrument for equipment leak detection in accordance with 40 CFR part 
60, subpart A, Sec.  60.18 of the Alternative work practice for 
monitoring equipment leaks, Sec.  60.18(i)(1)(i); Sec.  60.18(i)(2)(i) 
except that the monitoring frequency shall be annual using the 
detection

[[Page 56047]]

sensitivity level of 60 grams per hour as stated in 40 CFR part 60, 
subpart A, Table 1: Detection Sensitivity Levels; Sec.  60.18(i)(2)(ii) 
and (iii) except the gas chosen shall be methane, and Sec.  
60.18(i)(2)(iv) and (v); Sec.  60.18(i)(3); Sec.  60.18(i)(4)(i) and 
(v); including the requirements for daily instrument checks and 
distances, and excluding requirements for video records. Any emissions 
detected by the optical gas imaging instrument is a leak unless 
screened with Method 21 (40 CFR part 60, appendix A-7) monitoring, in 
which case 10,000 ppm or greater is designated a leak. In addition, you 
must operate the optical gas imaging instrument to image the source 
types required by this subpart in accordance with the instrument 
manufacturer's operating parameters. An optical gas imaging instrument 
must be used for all source types that are inaccessible and cannot be 
monitored without elevating the monitoring personnel more than 2 meters 
above a support surface.
    (2) Method 21. Use the equipment leak detection methods in 40 CFR 
part 60, appendix A-7, Method 21. If using Method 21 monitoring, if an 
instrument reading of 10,000 ppm or greater is measured, a leak is 
detected. Inaccessible emissions sources, as defined in 40 CFR part 60, 
are not exempt from this subpart. Owners or operators must use 
alternative leak detection devices as described in paragraph (a)(1) or 
(a)(2) of this section to monitor inaccessible equipment leaks or 
vented emissions.
* * * * *
    (5) Acoustic leak detection device. Use the acoustic leak detection 
device to detect through-valve leakage. When using the acoustic leak 
detection device to quantify the through-valve leakage, you must use 
the instrument manufacturer's calculation methods to quantify the 
through-valve leak. When using the acoustic leak detection device, if a 
leak of 3.1 scf per hour or greater is calculated, a leak is detected. 
In addition, you must operate the acoustic leak detection device to 
monitor the source valves required by this subpart in accordance with 
the instrument manufacturer's operating parameters. Acoustic 
stethoscope type devices designed to detect through valve leakage when 
put in contact with the valve body and that provide an audible leak 
signal but do not calculate a leak rate can be used to identify non-
leakers with subsequent measurement required to calculate the rate if 
through-valve leakage is identified. Leaks are reported if a leak rate 
of 3.1 scf per hour or greater is measured.
* * * * *
    (c) Use calibrated bags (also known as vent bags) only where the 
emissions are at near-atmospheric pressures and below the maximum 
temperature specified by the vent bag manufacturer such that the bag is 
safe to handle. The bag must be of sufficient size that the entire 
emissions volume can be encompassed for measurement.
* * * * *
    (d) * * *
    (3) Estimate natural gas volumetric emissions at standard 
conditions using calculations in Sec.  98.233(t). Estimate 
CH4 and CO2 volumetric and mass emissions from 
volumetric natural gas emissions using the calculations in Sec.  
98.233(u) and (v).
    16. Section 98.236 is amended by:
    a. Revising paragraphs (a) introductory text and (a)(8).
    b. Revising paragraph (b).
    c. Revising paragraphs (c) introductory text, (c)(1)(iv), 
(c)(2)(ii), and (c)(3)(ii) through (c)(3)(v); and adding paragraphs 
(c)(3)(vi) and (vii).
    d. Revising paragraphs (c)(4)(i)(H) and (C)(4)(i)(J); and adding 
paragraphs (c)(4)(i)(K) and (c)(4)(i)(L).
    e. Revising paragraphs (c)(4)(ii)(B) and (c)(4)(ii)(C); and adding 
paragraph (c)(4)(ii)(D).
    f. Revising paragraph (c)(4)(iii)(B).
    g. Revising paragraphs (c)(5) introductory text, (c)(5)(iii), and 
(c)(5)(vi); and adding paragraph (c)(5)(vii).
    h. Revising paragraphs (c)(6) introductory text, (c)(6)(i) 
introductory text, (c)(6)(i)(B), (c)(6)(i)(D), (c)(6)(i)(G), and 
(c)(6)(i)(H); and adding paragraph (c)(6)(ii)(I).
    i. Revising paragraphs (c)(6)(ii)(B) and (c)(6)(ii)(D); and adding 
paragraph (c)(6)(ii)(E).
    j. Revising paragraphs (c)(7)(i) and (c)(7)(ii); and adding 
paragraph (c)(7)(iii).
    k. Revising paragraphs (c)(8)(i) introductory text and 
(c)(8)(i)(J); and adding paragraphs (c)(8)(i)(K) through (c)(8)(i)(M).
    l. Revising paragraphs (c)(8)(ii) introductory text, (c)(8)(ii)(D), 
and (c)(8)(ii)(G); and adding paragraphs (c)(8)(ii)(H) and 
(c)(8)(ii)(I).
    m. Revising paragraphs (c)(8)(iii) introductory text and 
(c)(8)(iii)(F); and adding paragraphs (c)(8)(iii)(G) and 
(c)(8)(iii)(H).
    n. Adding paragraph (c)(8)(iv)(B).
    o. Revising paragraphs (c)(9)(i) and (c)(9)(ii); and adding 
paragraph (c)(9)(iii).
    p. Revising paragraphs (c)(10) introductory text and (c)(10)(iv); 
and adding paragraph (c)(10)(v).
    q. Revising paragraph (c)(11) introductory text and (c)(11)(iii); 
and adding paragraph (c)(11)(iv).
    r. Revising paragraph (c)(12)(vi) and adding paragraphs 
(c)(12)(vii) through (c)(12)(xi).
    s. Revising paragraphs (c)(15)(i)(B) and (c)(15)(i)(C).
    t. Revising paragraphs (c)(15)(ii)(A) through (c)(15)(ii)(C).
    u. Revising paragraphs (c)(16)(i) through (c)(16)(iv), (c)(16)(vi), 
and (c)(16)(xv).
    v. Removing and reserving paragraph (c)(16)(v).
    w. Adding paragraphs (c)(16)(xvi) through (c)(16)(xx).
    x. Revising paragraph (c)(17)(v) and adding paragraph (c)(17)(vi).
    y. Revising paragraph (c)(18) introductory text and paragraph 
(c)(18)(iii).
    z. Revising paragraph (c)(19)(iii) and (c)(19)(vi).
    aa. Adding paragraph (e).
    The revisions read as follows:


Sec.  98.236  Data Reporting Requirements.

* * * * *
    (a) Report annual emissions separately for each of the industry 
segments listed in paragraphs (a)(1) through (8) of this section.
* * * * *
    (8) Natural gas distribution.
    (b) For offshore petroleum and natural gas production, report 
emissions of CH4, CO2, and N2O as 
applicable to the source type (in metric tons CO2e per year 
at standard conditions) individually for all the emissions source types 
listed in the most recent BOEMRE study.
    (c) Report the information listed in this paragraph for each 
applicable source type. If a facility operates under more than one 
industry segment, each piece of equipment should be reported under its 
respective majority use segment. When a source type listed under this 
paragraph routes gas to flare, separately report the emissions that 
were vented directly to the atmosphere without flaring, and the 
emissions that resulted from flaring the gas. Both the vented and 
flared emissions will be reported under the respective source type and 
not under the flare source type.
    (1) * * *
    (iv) Report annual CO2 and CH4 emissions at 
the facility level, expressed in metric tons CO2e for each 
gas, for each of the following pieces of equipment: high bleed 
pneumatic devices; intermittent bleed pneumatic devices; low bleed 
pneumatic devices.

[[Page 56048]]

    (2) * * *
    (ii) Report annual CO2 and CH4 emissions at 
the facility level, expressed in metric tons CO2e for each 
gas, for all natural gas driven pneumatic pumps combined.
    (3) * * *
    (ii) For Calculation Methodology 1 and Calculation Methodology 2 of 
Sec.  98.233(d), annual average fraction of CO2 content in 
the vent from the acid gas removal unit (refer to Sec.  98.233(d)(6)).
    (iii) For Calculation Methodology 3 of Sec.  98.233(d), annual 
average volume fraction of CO2 content of natural gas into 
and out of the acid gas removal unit (refer to Sec.  98.233(d)(7) and 
(d)(8)).
    (iv) Report the annual quantity of CO2, expressed in 
metric tons CO2e, that was recovered from the AGR unit and 
transferred outside the facility.
    (v) Report annual CO2 emissions for the AGR unit, 
expressed in metric tons CO2e.
    (vi) A unique name or ID number for the AGR unit.
    (vii) An indication of which calculation methodology was used for 
the AGR.
    (4) * * *
    (i) * * *
    (H) Concentration of CH4 and CO2 in wet 
natural gas.
* * * * *
    (J) For each glycol dehydrator, report annual CO2 and 
CH4 emissions that resulted from venting gas directly to the 
atmosphere, expressed in metric tons CO2e for each gas.
    (K) For each glycol dehydrator, report annual CO2, 
CH4, and N2O emissions that resulted from flaring 
process gas from the dehydrator, expressed in metric tons 
CO2e for each gas.
    (L) A unique name or ID number for the glycol dehydrator.
    (ii) * * *
    (B) Which vent gas controls are used (refer to Sec.  98.233(e)(3) 
and (e)(4)).
    (C) Report annual CO2 and CH4 emissions at 
the facility level that resulted from venting gas directly to the 
atmosphere, expressed in metric tons CO2e for each gas, 
combined for all glycol dehydrators with a throughput of less than 0.4 
MMscfd.
    (D) Report annual CO2, CH4, and 
N2O emissions at the facility level that resulted from the 
flaring of process gas, expressed in metric tons CO2e for 
each gas, combined for all glycol dehydrators with a throughput of less 
than 0.4 MMscfd.
    (iii) * * *
    (B) Report annual CO2 and CH4 emissions at 
the facility level, expressed in metric tons CO2e for each 
gas, for all absorbent desiccant dehydrators combined.
    (5) For well venting for liquids unloading (refer to Equations W-7, 
W-8 and W-9 of Sec.  98.233), report the following by each well tubing 
diameter grouping and pressure grouping within each sub-basin category:
* * * * *
    (iii) Cumulative number of unloadings vented to the atmosphere.
* * * * *
    (vi) Report annual CO2 and CH4 emissions, 
expressed in metric tons CO2e for each gas, for each tubing 
diameter and pressure grouping within each sub-basin category.
    (vii) When using Calculation Methodology 1, casing diameter, depth 
and pressure of each well selected to represent emissions in that 
tubing size and pressure combination (refer to Equation W-7 of Sec.  
98.233).
    (6) For well completions and workovers, report the following for 
each sub-basin category:
    (i) For gas well completions and workovers with hydraulic 
fracturing by sub-basin and well type (horizontal or vertical) 
combination (refer to Equation W-10 of Sec.  98.233):
* * * * *
    (B) Average flow rate of the measured well completion venting in 
cubic feet per hour (refer to Equation W-12 of Sec.  98.233).
* * * * *
    (D) Average flow rate of the measured well workover venting in 
cubic feet per hour (refer to Equation W-12 of Sec.  98.233).
* * * * *
    (G) Report number of completions and number of workovers employing 
reduced emissions completions and engineering estimate based on best 
available data of the amount of gas recovered to sales.
    (H) Annual CO2 and CH4 emissions that 
resulted from venting gas directly to the atmosphere, expressed in 
metric tons CO2e for each gas.
    (I) Annual CO2, CH4, and N2O 
emissions that resulted from flares, expressed in metric tons 
CO2e for each gas.
* * * * *
    (B) Total count of workovers in calendar year that flare gas or 
vent gas to the atmosphere.
* * * * *
    (D) Annual CO2 and CH4 emissions that 
resulted from venting gas directly to the atmosphere, expressed in 
metric tons CO2e for each gas.
    (E) Annual CO2, CH4, and N2O 
emissions that resulted from flares, expressed in metric tons 
CO2e for each gas.
    (7) * * *
    (i) Total number of blowdowns per unique volume type in calendar 
year.
    (ii) Annual CO2 and CH4 emissions, expressed 
in metric tons CO2e for each gas, for each unique volume 
type, at each blowdown stack.
    (iii) A unique name or ID number for the blowdown vent stack.
    (8) * * *
    (i) For wellhead gas-liquid separator with oil throughput greater 
than or equal to 10 barrels per day, using Calculation Methodology 1 
and 2 of Sec.  98.233(j), report the following by sub-basin category, 
unless otherwise specified:
* * * * *
    (J) Annual CO2 and CH4 emissions that 
resulted from venting gas to the atmosphere, expressed in metric tons 
CO2e for each gas, for each wellhead gas-liquid separator or 
storage tank using Calculation Methodology 1 or 2 of Sec.  98.233(j).
    (K) Annual CO2 and CH4 gas quantities that 
were recovered, expressed in metric tons CO2e for each gas, 
for each wellhead gas-liquid separator or storage tank using 
Calculation Methodology 1 or 2 of Sec.  98.233(j).
    (L) Annual CO2, CH4, and N2O 
emissions that resulted from flaring gas, expressed in metric tons 
CO2e for each gas, for each wellhead gas-liquid separator or 
storage tank using Calculation Methodology 1 or 2 of Sec.  98.233(j).
    (M) A unique name or ID number for each wellhead gas liquid 
separator or storage tank.
    (ii) For wells with oil production greater than or equal to 10 
barrels per day, using Calculation Methodology 3 and 4 of Sec.  
98.233(j), report the following by sub-basin category:
* * * * *
    (D) Sales oil API gravity range for wells in (c)(8)(ii)(B) and 
(c)(8)(ii)(C) of this section, in degrees.
* * * * *
    (G) Annual CO2 and CH4 emissions that 
resulted from venting gas to the atmosphere, expressed in metric tons 
CO2e for each gas, at the sub-basin level for Calculation 
Methodology 3 or 4 of Sec.  98.233(j).
    (H) Annual CO2 and CH4 gas quantities that 
were recovered, expressed in metric tons CO2e for each gas, 
at the sub-basin level for Calculation Methodology 3 or 4 of Sec.  
98.233(j).
    (I) Annual CO2, CH4, and N2O 
emissions that resulted from flaring gas, expressed in metric tons 
CO2e for each gas, at the sub-basin level for

[[Page 56049]]

Calculation Methodology 3 and 4 of Sec.  98.233(j).
    (iii) For wellhead gas-liquid separators and wells with throughput 
less than 10 barrels per day, using Calculation Methodology 5 of Sec.  
98.233(j) Equation W-15 of Sec.  98.233, report the following:
* * * * *
    (F) Annual CO2 and CH4 emissions that 
resulted from venting gas to the atmosphere, expressed in metric tons 
CO2e for each gas, at the sub-basin level for Calculation 
Methodology 5 of Sec.  98.233(j).
    (G) Annual CO2 and CH4 gas quantities that 
were recovered, expressed in metric tons CO2e for each gas, 
at the sub-basin level for Calculation Methodology 5 of Sec.  
98.233(j).
    (H) Annual CO2, CH4, and N2O 
emissions that resulted from flaring gas, expressed in metric tons 
CO2e for each gas, at the sub-basin level for Calculation 
Methodology 5 of Sec.  98.233(j).
    (iv) * * *
    (B) Annual CO2 and CH4 emissions that 
resulted from venting gas to the atmosphere, expressed in metric tons 
CO2e for each gas, at the sub-basin level for improperly 
functioning dump valves.
    (9) * * *
    (i) For each transmission storage tank, report annual 
CO2 and CH4 emissions that resulted from venting 
gas directly to the atmosphere, expressed in metric tons 
CO2e for each gas.
    (ii) For each transmission storage tank, report annual 
CO2, CH4, and N2O emissions that 
resulted from flaring process gas from the transmission storage tank, 
expressed in metric tons CO2e for each gas.
    (iii) A unique name or ID number for the transmission storage tank.
    (10) For well testing venting and flaring (refer to Equation W-17 
of Sec.  98.233), report the following:
* * * * *
    (iv) Report annual CO2 and CH4 emissions at 
the facility level, expressed in metric tons CO2e for each 
gas, emissions from well testing venting.
    (v) Report annual CO2, CH4, and 
N2O emissions at the facility level, expressed in metric 
tons CO2e for each gas, emissions from well testing flaring.
    (11) For associated natural gas venting and flaring (refer to 
Equation W-18 of Sec.  98.233), report the following for each basin:
* * * * *
    (iii) Report annual CO2 and CH4 emissions at 
the facility level, expressed in metric tons CO2e for each 
gas, emissions from associated natural gas venting.
    (iv) Report annual CO2, CH4, and 
N2O emissions at the facility level, expressed in metric 
tons CO2e for each gas, emissions from associated natural 
gas flaring.
    (12) * * *
    (vi) Report uncombusted CH4 emissions, in metric tons 
CO2e (refer to Equation W-19 of Sec.  98.233).
    (vii) Report uncombusted CO2 emissions, in metric tons 
CO2e (refer to Equation W-20 of Sec.  98.233).
    (viii) Report combusted CO2 emissions, in metric tons 
CO2e (refer to Equation W-21 of Sec.  98.233).
    (ix) Report N2O emissions, in metric tons 
CO2e.
    (x) A unique name or ID number for the flare stack.
    (xi) In the case that a CEMS is used to measure CO2 
emissions for the flare stack, indicate that a CEMS was used in the 
annual report and report the combusted CO2 and uncombusted 
CO2 as a combined number.
    (15) * * *
    (i) * * *
    (B) For onshore natural gas processing, range of concentrations of 
CH4 and CO2 (refer to Equation W-30 of Sec.  
98.233).
    (C) Annual CO2 and CH4 emissions, in metric 
tons CO2e for each gas (refer to Equation W-30 of Sec.  
98.233), by equipment type.
    (ii) * * *
    (A) For source categories Sec.  98.230(a)(4), (a)(5), (a)(6), 
(a)(7), and (a)(8), total count for each type of leak source in Tables 
W-2, W-3, W-4, W-5, and W-6 of this subpart for which there is a 
population emission factor, listed by major heading and component type.
    (B) For onshore production (refer to Sec.  98.230 paragraph 
(a)(2)), total count for each type of major equipment in Table W-1B and 
Table W-1C of this subpart, by sub-basin category.
    (C) Annual CO2 and CH4 emissions, in metric 
tons CO2e for each gas (refer to Equation W-31 of Sec.  
98.233), by equipment type.
    (16) * * *
    (i) Number of above grade T-D transfer stations.
    (ii) Number of below grade T-D transfer stations.
    (iii) Number of above grade metering-regulating stations (this 
count will include above grade T-D transfer stations).
    (iv) Number of below grade metering-regulating stations (this count 
will include below grade T-D transfer stations).
    (v) [Reserved].
    (vi) Above grade metering-regulating station leak factor (refer to 
Equation W-32 of Sec.  98.233).
* * * * *
    (xv) Annual CO2 and CH4 emissions, in metric 
tons CO2e for each gas, from all above grade T-D transfer 
stations combined.
    (xvi) Annual CO2 and CH4 emissions, in metric 
tons CO2e for each gas, from all below grade T-D transfer 
stations combined.
    (xvii) Annual CO2 and CH4 emissions, in 
metric tons CO2e for each gas, from all above grade 
metering-regulating stations (including T-D transfer stations) 
combined.
    (xviii) Annual CO2 and CH4 emissions, in 
metric tons CO2e for each gas, from all below grade 
metering-regulating stations (including T-D transfer stations) 
combined.
    (xix) Annual CO2 and CH4 emissions, in metric 
tons CO2e for each gas, from all distribution mains 
combined.
    (xx) Annual CO2 and CH4 emissions, in metric 
tons CO2e for each gas, from all distribution services 
combined.
    (17) * * *
    (v) For each EOR pump, report annual CO2 and 
CH4 emissions, expressed in metric tons CO2e for 
each gas.
    (vi) A unique name or ID for the EOR pump.
    (18) For EOR hydrocarbon liquids dissolved CO2 for each 
sub-basin category (refer to Equation W-38 of Sec.  98.233), report the 
following:
* * * * *
    (iii) Report annual CO2 emissions at the sub-basin 
level, expressed in metric tons CO2e.
    (19) * * *
    (iii) Report annual CO2, CH4, and 
N2O emissions from external fuel combustion units with a 
rated heat capacity larger than 5 mmBtu/hr, expressed in metric tons 
CO2e for each gas, by type of unit.
* * * * *
    (vi) Report annual CO2, CH4, and 
N2O emissions from internal combustion units, expressed in 
metric tons CO2e for each gas, by type of unit.
* * * * *
    (e) For onshore petroleum and natural gas production, report the 
average API gravity, average gas to oil ratio, and average low pressure 
separator pressure for each sub-basin category.
    17. Section 98.237 is amended by adding paragraph (e) to read as 
follows:


Sec.  98.237  Records that must be retained.

* * * * *
    (e) The records required under Sec.  98.3(g)(2)(i) shall include an 
explanation of how company records,

[[Page 56050]]

engineering estimation, or best available information are used to 
calculate each applicable parameter under this subpart.
    18. Section 98.238 is amended by:
    a. Revising the definitions of ``Facility with respect to natural 
gas distribution for purposes of this subpart and subpart A'', 
``Facility with respect to onshore petroleum and natural gas production 
for purposes of this subpart and for subpart A'', ``Farm Taps'', and 
``Transmission pipeline''.
    b. Adding definitions of ``Associated with a single well-pad'', 
``Distribution pipeline'', ``Flare'', ``Forced extraction'', 
``Horizontal well'', ``Natural gas'', ``Metering-regulating station'', 
``Pressure groupings'', ``Sub-basin category'', ``Transmission-
distribution transfer station'', ``Tubing diameter groupings'', 
``Tubing systems'', ``Vertical well'', and ``Well testing venting and 
flaring''.
    c. Removing the definition of ``Field''.
    The revisions read as follows:


Sec.  98.238  Definitions.

* * * * *
    Associated with a single well-pad means associated with the 
hydrocarbon stream as produced from one or more wells located on that 
single well-pad. The association ends where the stream from a single 
well-pad is combined with streams from one or more additional single 
well-pads, where the point of combination is located off that single 
well-pad. This does not include storage and condensate tanks that are 
located downstream of the point of combination.
* * * * *
    Distribution pipeline means a pipeline that is designated as such 
by the Pipeline and Hazardous Material Safety Administration (PHMSA) 49 
CFR 192.3.
* * * * *
    Facility with respect to natural gas distribution for purposes of 
reporting under this subpart and for the corresponding subpart A 
requirements means the collection of all distribution pipelines and 
metering-regulating stations that are operated by a Local Distribution 
Company (LDC) within a single state that is regulated as a separate 
operating company by a public utility commission or that are operated 
as an independent municipally-owned distribution system.
    Facility with respect to onshore petroleum and natural gas 
production for purposes of reporting under this subpart and for the 
corresponding subpart A requirements means all petroleum or natural gas 
equipment on a well-pad or associated with a well-pad and 
CO2 EOR operations that are under common ownership or common 
control including leased, rented, or contracted activities by an 
onshore petroleum and natural gas production owner or operator and that 
are located in a single hydrocarbon basin as defined in Sec.  98.238. 
Where a person or entity owns or operates more than one well in a 
basin, then all onshore petroleum and natural gas production equipment 
associated with all wells that the person or entity owns or operates in 
the basin would be considered one facility.
    Farm Taps are pressure regulation stations that deliver gas 
directly from transmission pipelines to generally rural customers. In 
some cases a nearby LDC may handle the billing of the gas to the 
customer(s).
* * * * *
    Flare, for the purposes of subpart W, means a combustion device, 
whether at ground level or elevated, that uses an open or closed flame 
to combust waste gases without energy recovery.
* * * * *
    Forced extraction of natural gas liquids means removal of ethane or 
higher carbon number hydrocarbons existing in the vapor phase in 
natural gas, by removing ethane or heavier hydrocarbons derived from 
natural gas into natural gas liquids by means of a forced extraction 
process. Forced extraction processes include but are not limited to 
refrigeration, absorption (lean oil), cryogenic expander, and 
combinations of these processes. Forced extraction does not include in 
and of itself; natural gas dehydration, or the collection or gravity 
separation of water or hydrocarbon liquids from natural gas at ambient 
temperature or heated above ambient temperatures, or the condensation 
of water or hydrocarbon liquids through passive reduction in pressure 
or temperature, or portable dewpoint suppression skids.
* * * * *
    Horizontal well means a well bore that has a planned deviation from 
primarily vertical to a primarily horizontal inclination or declination 
tracking in parallel with and through the target formation.
* * * * *
    Natural gas means a naturally occurring mixture or process 
derivative of hydrocarbon and non-hydrocarbon gases found in geologic 
formations beneath the earth's surface, of which its constituents 
include, but are not limited to, methane, heavier hydrocarbons and 
carbon dioxide. Natural gas may be field quality, pipeline quality, or 
process gas.
    Metering-regulating station means a station that meters the 
flowrate, regulates the pressure, or both, of natural gas in a natural 
gas distribution facility. This does not include customer meters, 
customer regulators, or farm taps.
* * * * *
    Pressure groupings are defined as follows: less than or equal to 25 
psig; greater than 25 psig and less than or equal to 60 psig; greater 
than 60 psig and less than or equal to 110 psig; greater than 110 psig 
and less than or equal to 200 psig; and greater than 200 psig.
* * * * *
    Sub-basin category, for onshore natural gas production, means a 
subdivision of a basin into the unique combination of wells with the 
surface coordinates within the boundaries of an individual county and 
subsurface completion in one or more of each of the following four 
formation types as designated by 18 CFR 270.305: conventional with >0.1 
millidarcy permeability, and unconventional with <=0.1 millidarcy 
permeability. Unconventional formation types are either shale, coal 
seam, or other tight reservoir rock. Wells producing from more than one 
unconventional formation type shall be classified into only one type 
based on the formation with the most contribution to production as 
determined by engineering knowledge. Unconventional wells producing in 
two or more formation types of ``shale and coal seam'', ``shale and 
other tight'', or ``shale, coal seam, and other tight''; are considered 
shale. In addition, unconventional wells producing in ``coal seam and 
other tight'' formations are considered coal.
    Transmission-distribution (TD) transfer station means a meter-
regulating station where a local distribution company takes part or all 
of the natural gas from a transmission pipeline and puts it into a 
distribution pipeline.
    Transmission pipeline means a Federal Energy Regulatory Commission 
rate-regulated Interstate pipeline, a state rate-regulated Intrastate 
pipeline, or a pipeline that falls under the ``Hinshaw Exemption'' as 
referenced in section 1(c) of the Natural Gas Act, 15 U.S.C. 717-
717(w)(1994).
    Tubing diameter groupings are defined as follows: less than or 
equal to 1 inch; greater than 1 inch and less than 2 inch; and greater 
than or equal to 2 inch.
    Tubing systems means piping equal to or less than one half inch 
diameter as per nominal pipe size.
* * * * *
    Vertical well means a well bore that is primarily vertical but has 
some

[[Page 56051]]

unintentional deviation or one or more intentional deviations to enter 
one or more subsurface targets that are off-set horizontally from the 
surface location, intercepting the targets either vertically or at an 
angle.
    Well testing venting and flaring means venting and/or flaring of 
natural gas at the time the production rate of a well is determined 
(i.e., the well testing) through a choke (an orifice restriction). If 
well testing is conducted immediately after well completion or 
workover, then it is considered part of well completion or workover.
    19. Table W-7 to subpart W is amended by:
    a. Revising the entries for ``Leaker Emission Factors--Above Grade 
M&R at City Gate \1\ Stations Components, Gas Service,'' ``Population 
Emission Factors--Below Grade M&R \2\ Components, Gas Service \3\,'' 
``Population Emission Factors--Distribution Mains, Gas Service \4\,'' 
and ``Population Emission Factors--Distribution Services, Gas Service 
\5\.''
    b. Removing Footnote 1.
    c. Redesignating Footnotes 2, 3, 4, and 5 as Footnotes 1, 2, 3, and 
4.
    The revisions read as follows:

 
------------------------------------------------------------------------
                              * * * * * * *
------------------------------------------------------------------------
Leaker Emission Factors--Transmission-distribution Transfer Station\1\
 Components, Gas Service
------------------------------------------------------------------------
 
                              * * * * * * *
------------------------------------------------------------------------
Population Emission Factors--Below Grade Metering-Regulating station\1\
 Components, Gas Service\2\
------------------------------------------------------------------------
 
                              * * * * * * *
------------------------------------------------------------------------
Population Emission Factors--Distribution Mains, Gas Service\3\
------------------------------------------------------------------------
 
                              * * * * * * *
------------------------------------------------------------------------
Population Emission Factors--Distribution Services, Gas Service\4\
------------------------------------------------------------------------
 
                              * * * * * * *
------------------------------------------------------------------------
\1\ Excluding customer meters.
\2\ Emission Factor is in units of ``scf/hour/station.''
\3\ Emission Factor is in units of ``scf/hour/mile.''
\4\ Emission Factor is in units of ``scf/hour/number of services.''

[FR Doc. 2011-21725 Filed 9-8-11; 8:45 am]
BILLING CODE 6560-50-P