[Federal Register Volume 79, Number 227 (Tuesday, November 25, 2014)]
[Rules and Regulations]
[Pages 70352-70425]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2014-27681]



[[Page 70351]]

Vol. 79

Tuesday,

No. 227

November 25, 2014

Part IV





Environmental Protection Agency





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40 CFR Part 98





Greenhouse Gas Reporting Rule: 2014 Revisions and Confidentiality 
Determinations for Petroleum and Natural Gas Systems; Final Rule

Federal Register / Vol. 79 , No. 227 / Tuesday, November 25, 2014 / 
Rules and Regulations

[[Page 70352]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 98

[EPA-HQ-OAR-2011-0512; FRL-9918-95-OAR]
RIN 2060-AR96


Greenhouse Gas Reporting Rule: 2014 Revisions and Confidentiality 
Determinations for Petroleum and Natural Gas Systems

AGENCY: Environmental Protection Agency.

ACTION: Final rule.

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SUMMARY: The Environmental Protection Agency (EPA) is finalizing 
revisions and confidentiality determinations for the petroleum and 
natural gas systems source category and the general provisions of the 
Greenhouse Gas Reporting Rule. These revisions include changes to 
certain calculation methods, amendments to certain monitoring and data 
reporting requirements, clarification of certain terms and definitions, 
and corrections to certain technical and editorial errors that have 
been identified during the course of implementation. This action also 
finalizes confidentiality determinations for new or substantially 
revised data elements contained in these amendments and revises the 
confidentiality determination for one existing data element.

DATES: This final rule is effective on January 1, 2015.

ADDRESSES: 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., confidential business 
information (CBI) or other information whose disclosure is restricted 
by statute. Certain other material, such as copyrighted material, will 
be publicly available only in hard copy. Publicly available docket 
materials are available either electronically in http://www.regulations.gov or in hard copy at the Air Docket, EPA/DC, WJC 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-6207A), Environmental Protection 
Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone 
number: (202) 343-9263; fax number: (202) 343-2342; email address: 
<a href="/cdn-cgi/l/email-protection#6a2d222d380f1a05181e03040d381f060f2a0f1a0b440d051c"><span class="__cf_email__" data-cfemail="1a5d525d487f6a75686e73747d486f767f5a7f6a7b347d756c">[email protected]</span></a>. For technical information, please go to the 
Greenhouse Gas Reporting Rule Web site, http://www.epa.gov/ghgreporting/. To submit a question, select Help Center, followed by 
``Contact Us.''
    Worldwide Web (WWW). In addition to being available in the docket, 
an electronic copy of this final rule will also be available through 
the WWW. Following the Administrator's signature, a copy of this action 
will be posted on the EPA's Greenhouse Gas Reporting Rule Web site at 
http://www.epa.gov/ghgreporting/index.html.

SUPPLEMENTARY INFORMATION:
    Regulated Entities. This final rule revises certain calculation 
methods, monitoring, and data reporting requirements and finalizes 
confidentiality determinations for the petroleum and natural gas 
systems source category and the general provisions of the Greenhouse 
Gas Reporting Rule (40 CFR part 98). The Administrator determined that 
40 CFR part 98 is subject to the provisions of Clean Air Act (CAA) 
section 307(d). See CAA section 307(d)(1)(V) (the provisions of section 
307(d) apply to ``such other actions as the Administrator may 
determine''). Entities affected by this final rule are owners and 
operators of petroleum and natural gas systems that directly emit 
greenhouse gases (GHGs), which include those listed in Table 1 of this 
preamble:

           Table 1--Examples of Affected Entities by Category
------------------------------------------------------------------------
                                                    Examples of affected
             Category                    NAICS           facilities
------------------------------------------------------------------------
Petroleum and Natural Gas Systems.          211111  Crude petroleum and
                                                     natural gas
                                                     extraction.
                                            211112  Natural gas liquid
                                                     extraction.
                                            221210  Natural gas
                                                     distribution.
                                            486210  Pipeline
                                                     transportation of
                                                     natural gas.
------------------------------------------------------------------------

    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. Types of facilities other than those listed in 
the table could also be subject to reporting requirements. To determine 
whether you are affected by this action, you should carefully examine 
the applicability criteria found in 40 CFR part 98, subpart A 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.
    What is the effective date? The final rule is effective on January 
1, 2015. Section 553(d) of the Administrative Procedure Act (APA), 5 
U.S.C. Chapter 5, generally provides that rules may not take effect 
earlier than 30 days after they are published in the Federal Register. 
The EPA is issuing this final rule under section 307(d)(1) of the Clean 
Air Act, which states: ``The provisions of section 553 through 557 * * 
* of Title 5 shall not, except as expressly provided in this section, 
apply to actions to which this subsection applies.'' Thus, section 
553(d) of the APA does not apply to this rule. The EPA is nevertheless 
acting consistently with the purposes underlying APA section 553(d) in 
making this rule effective on January 1, 2015. Section 5 U.S.C. 
553(d)(3) allows an effective date less than 30 days after publication 
``as otherwise provided by the agency for good cause found and 
published with the rule.'' As explained below, the EPA finds that there 
is good cause for this rule to become effective on January 1, 2015, 
even though this may result in an effective date fewer than 30 days 
from date of publication in the Federal Register.
    While this action is being signed prior to December 1, 2014, there 
is likely to be a significant delay in the publication of this rule as 
it contains complex equations and tables and is relatively long. As an 
example, the EPA Administrator signed the Revisions and Confidentiality 
Determinations for Petroleum and Natural Gas Systems proposed rule on 
February 7, 2014, but the proposed rule was not published in the 
Federal Register until March 10, 2014 (79 FR 13394). The purpose of the 
30-day waiting period prescribed in 5 U.S.C. 553(d) is to give affected 
parties a reasonable time to adjust their

[[Page 70353]]

behavior and prepare before the final rule takes effect.
    To employ the 5 U.S.C. 553(d)(3) ``good cause'' exemption, an 
agency must balance the necessity for immediate implementation against 
principles of fundamental fairness which require that all affected 
persons be afforded a reasonable amount of time to prepare for the 
effective date of its ruling.\1\ Where, as here, the final rule will be 
signed and made available on the EPA Web site more than 30 days before 
the effective date, but where the publication is likely to be delayed 
due to the complexity and length of the rule, the regulated entities 
are afforded this reasonable amount of time. This is particularly true 
given that many of the revisions being made in this package provide 
flexibilities to sources covered by the reporting rule, or otherwise 
relieve a restriction. We balance these circumstances with the need for 
the amendments to be effective by January 1, 2015; a delayed effective 
date would result in regulatory uncertainty, program disruption, and an 
inability to have the amendments (many of which clarify requirements, 
relieve burden, and/or are made at the request of the regulated 
facilities) effective for the 2015 reporting year. Accordingly, we find 
good cause exists to make this rule effective on January 1, 2015, 
consistent with the purposes of 5 U.S.C. 553(d)(3).
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    \1\ Omnipoint Corp. v. FCC, 78 F3d 620, 630 (D.C. Cir. 1996), 
quoting U.S. v. Gavrilovic, 551 F.2d 1099, 1105 (8th Cir. 1977).
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    Judicial Review. Under CAA section 307(b)(1), judicial review of 
this final rule is available only by filing a petition for review in 
the U.S. Court of Appeals for the District of Columbia Circuit (the 
Court) by January 26, 2015. Under CAA section 307(d)(7)(B), only an 
objection to this final rule that was raised with reasonable 
specificity during the period for public comment can be raised during 
judicial review. Section 307(d)(7)(B) of the CAA also provides a 
mechanism for the EPA to convene a proceeding for reconsideration, 
``[i]f the person raising an objection can demonstrate to the EPA that 
it was impracticable to raise such objection within [the period for 
public comment] or if the grounds for such objection arose after the 
period for public comment (but within the time specified for judicial 
review) and if such objection is of central relevance to the outcome of 
the rule.'' Any person seeking to make such a demonstration to us 
should submit a Petition for Reconsideration to the Office of the 
Administrator, Environmental Protection Agency, Room 3000, William 
Jefferson Clinton Building, 1200 Pennsylvania Ave. NW., Washington, DC 
20460, with a copy to the person listed in the preceding FOR FURTHER 
INFORMATION CONTACT section, and the Associate General Counsel for the 
Air and Radiation Law Office, Office of General Counsel (Mail Code 
2344A), Environmental Protection Agency, 1200 Pennsylvania Ave. NW., 
Washington, DC 20004. Note that under CAA section 307(b)(2), the 
requirements established by this final rule may not be challenged 
separately in any civil or criminal proceedings brought by the EPA to 
enforce these requirements.
    Acronyms and Abbreviations. The following acronyms and 
abbreviations are used in this document.

AGR--acid gas removal
APA--Administrative Procedure Act
API--American Petroleum Institute
BAMM--best available monitoring methods
CAA--Clean Air Act
CBI--confidential business information
CFR--Code of Federal Regulations
CH<INF>4</INF>--methane
CO<INF>2</INF>--carbon dioxide
CO<INF>2</INF>e--carbon dioxide equivalent
EIA--Energy Information Administration
EPA--U.S. Environmental Protection Agency
FERC--Federal Energy Regulatory Commission
FR--Federal Register
GHG--greenhouse gas
GOR--gas to oil ratio
HHV--higher heating value
hp--horsepower
ICR--information collection request
ID--identification
IR--infrared
LNG--liquefied natural gas
mmBtu--million British thermal units
MMscf--million standard cubic feet
N<INF>2</INF>O--nitrous oxide
NAICS--North American Industry Classification System
NESHAP--National Emission Standards for Hazardous Air Pollutants
NGL--natural gas liquids
NOD--not-operating-depressurized
NSPS--New Source Performance Standards
NTTAA--National Technology Transfer and Advancement Act
O&M--operation and maintenance
OMB--Office of Management and Budget
psig--pounds per square inch gauge
QA/QC--quality assurance/quality control
REC--reduced emissions completion
RFA--Regulatory Flexibility Act
scf--standard cubic feet
U.S.--United States
UMRA--Unfunded Mandates Reform Act of 1995
WWW--worldwide web

    Organization of This Document. The following outline is provided to 
aid in locating information in this preamble.

I. Background
    A. Organization of This Preamble
    B. Background on This Action
    C. Legal Authority
    D. How do these amendments apply to 2014 and 2015 reports?
II. Summary of Final Revisions and Other Amendments to Subpart W and 
Responses to Public Comment
    A. Summary of Final Revisions to Provide Consistency Throughout 
Subpart W
    B. Summary of Final Revisions to Calculation Methods and 
Reporting Requirements
    C. Summary of Final Revisions to Missing Data Provisions
    D. Summary of Final Amendments to Best Available Monitoring 
Methods
    E. Summary of Final Additions of New Data Elements and Revisions 
to Reporting Requirements
III. Final Confidentiality Determinations
    A. Summary of Final Confidentiality Determinations for New or 
Revised Subpart W Data Elements
    B. Summary of Public Comments and Responses on the Proposed 
Confidentiality Determinations
IV. Impacts of the Final Amendments to Subpart W
    A. Impacts of the Final Amendments
    B. Summary of Comments and Responses on the Impacts of the 
Proposed Rule
V. 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 Concerning Regulations That 
Significantly Affect Energy Supply, Distribution or Use
    I. National Technology Transfer and Advancement Act (NTTAA)
    J. Executive Order 12898: Federal Actions to Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. Congressional Review Act

I. Background

A. Organization of This Preamble

    Section I of this preamble provides background information 
regarding the origin of the final amendments. This section also 
discusses the EPA's legal authority under the CAA to promulgate and 
amend 40 CFR part 98 of the Greenhouse Gas Reporting Rule (hereinafter 
referred to as ``Part 98'') as well as the legal authority for making 
confidentiality determinations for the data to be reported. Section II 
of this preamble contains information on the final revisions to Part 
98, subpart W (Petroleum and Natural Gas Systems) (hereinafter referred 
to as ``subpart W''), including a summary of the major comments that 
the EPA considered in

[[Page 70354]]

the development of this final rule. Section III of this preamble 
discusses the final confidentiality determinations for new or 
substantially revised (i.e., requiring additional or different data to 
be reported) data reporting elements, as well as a revised 
confidentiality determination for one existing data element. Section IV 
of this preamble discusses the impacts of the final amendments to 
subpart W. Finally, Section V of this preamble describes the statutory 
and executive order requirements applicable to this action.

B. Background on This Action

    On October 30, 2009, the EPA published Part 98 for collecting 
information regarding GHGs from a broad range of industry sectors (74 
FR 56260). The 2009 rule, which finalized reporting requirements for 29 
source categories, did not include the Petroleum and Natural Gas 
Systems source category. A subsequent rule was published on November 
30, 2010, finalizing the requirements for the Petroleum and Natural Gas 
Systems source category at 40 CFR part 98, subpart W (75 FR 74458) 
(hereinafter referred to as ``the subpart W 2010 final rule''). 
Following promulgation, the EPA finalized several actions revising 
subpart W (76 FR 22825, April 25, 2011; 76 FR 59533, September 27, 
2011; 76 FR 80554, December 23, 2011; 77 FR 51477, August 24, 2012; 78 
FR 25392, May 1, 2013; 78 FR 71904, November 29, 2013; 79 FR 63750, 
October 24, 2014).
    On March 10, 2014, the EPA proposed the ``Revisions and 
Confidentiality Determinations for Petroleum and Natural Gas Systems; 
Proposed Rule'' (79 FR 13394) to make revisions to certain provisions 
of subpart W, including the clarification and correction of certain 
calculation methods, monitoring, and reporting requirements for which 
errors were identified during the course of implementation. At that 
time, the EPA also proposed confidentiality determinations for new and 
substantially revised (i.e., requiring additional or different data to 
be reported) data elements contained in the proposed amendments, as 
well as a revised confidentiality determination for one existing data 
element. The public comment period for these proposed rule amendments 
ended on April 24, 2014.
    In this action, the EPA is finalizing certain revisions to the 
subpart W calculation, monitoring, and reporting requirements with some 
changes made in response to public comments and one clarifying edit, as 
proposed, to a definition in the general provisions (Part 98, subpart 
A) that applies to subpart W reporters. Responses to comments submitted 
on the proposed amendments can be found in Sections II, III, and IV of 
this preamble as well as in the 2014 response to comment document in 
Docket Id. No. EPA-HQ-OAR-2011-0512.

C. Legal Authority

    The EPA is finalizing these rule amendments under its existing CAA 
authority provided in CAA section 114. As stated in the preamble to the 
2009 final GHG reporting rule (74 FR 56260, October 30, 2009), CAA 
section 114(a)(1) provides the EPA broad authority to require the 
information to be gathered by this rule because such data would inform 
and are relevant to the EPA's carrying out a wide variety of CAA 
provisions. See the preambles to the proposed (74 FR 16448, April 10, 
2009) and final GHG reporting rule (74 FR 56260, October 30, 2009) for 
further information.
    In addition, pursuant to sections 114, 301, and 307 of the CAA, the 
EPA is publishing final confidentiality determinations for the new or 
substantially revised data elements and a revised confidentiality 
determination for one existing data element, required by these 
amendments. Section 114(c) requires that the EPA make information 
obtained under section 114 available to the public, except for 
information that qualifies for confidential treatment. The 
Administrator has determined that this action is subject to the 
provisions of section 307(d) of the CAA.

D. How do these amendments apply to 2014 and 2015 reports?

    These amendments are effective on January 1, 2015. Thus, beginning 
on January 1, 2015, facilities must follow the revised methods in 
subpart W, as amended, to calculate emissions occurring during the 2015 
calendar year. The first annual reports of emissions calculated using 
the amended requirements will be those submitted by March 31, 2016, 
covering the 2015 calendar year. For the 2014 calendar year, reporters 
will continue to calculate emissions and other relevant data for the 
reports that are submitted according to the requirements in Part 98 
that are applicable to the 2014 calendar year (i.e., the requirements 
in place until the effective date of this final rule). For this reason, 
we determined that it was not appropriate to revise Table A-7 to 
subpart A of Part 98 to reflect the revised reporting requirement 
section references in this final rule. For the 2011 through 2014 
calendar years, subpart W reporters must report any data that are 
inputs to emissions equations according to the requirements in 40 CFR 
98.3(c)(vii) and in Table A-7 to subpart A of Part 98 following the 
requirements in Part 98 that are applicable for that calendar year. For 
more information on the reporting of 2011 through 2014 data that are 
inputs to emissions equations, see 79 FR 63750 (October 24, 2014).
    As noted in Section II.D of this preamble, we are providing short-
term transitional best available monitoring methods (BAMM) for 
reporters for emission sources that are subject to new monitoring or 
measurement requirements as part of these final revisions. These 
reporters have the option of using BAMM from January 1, 2015, to March 
31, 2015, without seeking prior EPA approval for certain parameters 
that cannot reasonably be measured according to the monitoring and 
quality assurance/quality control (QA/QC) requirements of 40 CFR 
98.234. Reporters also have the opportunity to request an extension for 
the use of BAMM from April 1, 2015, through December 31, 2015; those 
owners or operators must submit a request to the EPA by January 31, 
2015.

II. Summary of Final Revisions and Other Amendments to Subpart W and 
Responses to Public Comment

    The EPA is finalizing technical corrections, clarifying revisions, 
and other amendments to subpart W. These final amendments improve the 
quality and consistency of the collected data, and many of the changes 
are in response to feedback received from stakeholders during program 
implementation. These final amendments include changes to clarify or 
simplify calculation methods for certain sources at a facility; 
revisions to units of measure, terms, and definitions in certain 
equations to provide consistency throughout the rule, provide clarity, 
or better reflect facility operations; revisions to reporting 
requirements to clarify and align more closely with the calculation 
methods and to clearly identify the data that must be reported; and 
other revisions identified as a result of working with the affected 
sources.
    Sections II.A through II.E of this preamble describe the 
corrections and other amendments that we are finalizing in this 
rulemaking. Section II.A describes revisions which provide consistency 
throughout subpart W, including revisions to definitions. Section II.B 
describes the final revisions to calculation methods and reporting 
requirements for the emission source types identified in subpart W. 
Section II.C describes the final revisions to the

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missing data procedures of subpart W. Subpart II.D provides a summary 
of the final amendments to the best available monitoring requirements. 
Finally, Section II.E describes the final additions of new data 
elements and revisions to reporting requirements. The amendments 
described in each section are followed by a summary of the major 
comments on those amendments and the EPA's responses. See the 2014 
response to comment document in Docket Id. No. EPA-HQ-OAR-2011-0512 for 
a complete listing of all comments and the EPA's responses.
    In addition to the specific revisions or amendments discussed in 
this section of the preamble, the EPA is finalizing minor technical 
revisions to subpart W. These revisions improve readability, create 
consistency in terminology, and/or correct typographical or other 
errors in subpart W to improve the final rule. These final revisions 
are further explained in the memorandum, ``Minor Technical Corrections 
to Subpart W, Greenhouse Gas Reporting Rule: 2014 Revisions and 
Confidentiality Determinations for Petroleum and Natural Gas Systems; 
Final Rule'' and the 2014 response to comment document in Docket Id. 
No. EPA-HQ-OAR-2011-0512.

A. Summary of Final Revisions To Provide Consistency Throughout Subpart 
W

    This section includes minor cascading revisions that affect 
multiple requirements of subpart W. Sections II.A.1 through II.A.3 
describe the amendments we are finalizing in this rulemaking and, if 
major comments were received, provide a summary of the major comments 
and the EPA's responses.
1. Consistency in Units of Measure for Emissions Reporting
    The EPA is amending 40 CFR 98.236 to revise the reporting of GHG 
emissions from units of metric tons of carbon dioxide equivalent 
(CO<INF>2</INF>e) of each reported GHG to metric tons of each reported 
GHG. Specifically, we are revising the units of emissions reported in 
40 CFR 98.236 to require reporting in metric tons of methane 
(CH<INF>4</INF>), carbon dioxide (CO<INF>2</INF>), and nitrous oxide 
(N<INF>2</INF>O), as applicable, instead of reporting each gas in 
metric tons of CO<INF>2</INF>e. The cumulative GHG emissions in units 
of metric tons of CO<INF>2</INF>e across all pollutants will also be 
reported as required in the general provisions at 40 CFR 98.3(c)(4)(i). 
These changes increase consistency between the reporting requirements 
for subpart W and the rest of Part 98, which generally requires the 
reporting of metric tons of individual GHGs. The EPA received only 
supportive comments to these revisions. The final amendments remove a 
reference to CO<INF>2</INF>e in the introductory paragraph of 40 CFR 
98.236(a) that was inadvertently retained in the proposal. Otherwise, 
these revisions are finalized as proposed.
2. Onshore Production Source Category Definition
a. Summary of Final Revisions
    We are finalizing, with minor changes from proposal, amendments to 
the source category definition of ``onshore petroleum and natural gas 
production'' at 40 CFR 98.230(a)(2) to clarify the emission sources 
covered for purposes of GHG reporting. As proposed, we are adding 
references to engines, boilers, heaters, flares, and separation and 
processing equipment, and we are removing references to gravity 
separation equipment and auxiliary non-transportation-related equipment 
for being redundant with other sources specified in the definition. In 
this final rule, we are not including the reference to ``maintenance 
and repair equipment'' that was included in the proposed rule after 
considering public comments indicating confusion regarding that 
proposed text. Thus, the first sentence of 40 CFR 98.230(a)(2) reads, 
``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, 
engines, boilers, heaters, flares, separation and processing equipment, 
and portable non-self-propelled equipment, which includes well drilling 
and completion equipment, workover 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).''
b. Summary of Comments and Responses
    This section summarizes the major comments and responses related to 
the proposed amendments to the source category definition of ``onshore 
petroleum and natural gas production.'' See the 2014 response to 
comment document in Docket Id. No. EPA-HQ-OAR-2011-0512 for a complete 
listing of all comments and the EPA's responses.
    Comment: Two commenters supported part of the proposed revisions to 
the source category definition of ``onshore petroleum and natural gas 
production'' at 40 CFR 98.230(a)(2). These commenters supported the 
removal of the term ``auxiliary non-transportation related equipment'' 
but objected to the addition of the term ``maintenance and repair 
equipment.'' One commenter asserted that based on the current rule 
language, maintenance and repair equipment is not included in the 
onshore production industry segment because this equipment is not 
directly used in the production, extraction, recovery, lifting, 
stabilization, separation, or treating of petroleum and natural gas. 
Two commenters pointed to the description of stationary or portable 
fuel combustion equipment in 40 CFR 98.232(c)(22), which includes only 
emissions from equipment that is ``integral to the extraction, 
processing, or movement of oil or natural gas.'' These commenters 
asserted that maintenance and repair equipment is not integral. The 
commenters stated that the proposed rule expands the definition, which 
places an undue burden on industry because emissions from maintenance 
and repair equipment, such as welding machines and pressure washers, 
are small relative to integral equipment like prime movers, and the 
equipment is frequently moved between well sites and tracking is 
difficult. The commenters requested that the EPA remove the term 
``maintenance and repair equipment'' from the final definition.
    Response: The EPA recognizes that, by specifically including 
reference to maintenance and repair equipment within the parenthetical, 
some reporters may misinterpret that to mean all maintenance and repair 
equipment, regardless of whether or not that equipment is actually used 
in the production, extraction, recovery, lifting, stabilization, and 
separation or treating of petroleum and/or natural gas. This was not 
our intent. To reduce the potential for confusion, we are removing the 
reference to ``maintenance and repair equipment'' from the source 
category definition for the onshore petroleum and natural gas 
production segment in this final rule. However, the EPA notes that the 
parenthetical list is not an all-inclusive list (``. . . including but 
not limited to . . .'') and, as noted at 40 CFR 98.232(c)(22), if the 
facility has maintenance and repair equipment that is integral to the 
continued production, extraction, recovery, lifting, stabilization, 
separation or treating of petroleum and/or natural gas, then it would 
be covered by the onshore petroleum and natural gas production segment.

[[Page 70356]]

    With respect to the need to determine combustion emissions from 
maintenance and repair equipment, 40 CFR 98.232(c)(22) requires 
emissions ``. . . from stationary or portable fuel combustion equipment 
that cannot move under its own power or drive train, and that is 
located at an onshore petroleum and natural gas production facility . . 
.'' to be reported. 40 CFR 98.232(c)(22) further specifies that 
``[s]tationary 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.'' The list provided in 
40 CFR 98.232(c)(7)(22) is not open-ended and few pieces of 
``maintenance and repair equipment'' would qualify as ``stationary or 
portable equipment'' for which combustion emissions must be calculated 
and reported. If the maintenance and repair equipment have applicable 
combustion emissions, reporters must report the emissions from this 
equipment provided that it includes external combustion sources with 
rated heat capacity greater than 5 million British thermal units 
(mmBtu) per hour or internal fuel combustion sources with rated heat 
capacity greater than 1 mmBtu per hour (or 130 horsepower (hp)), as 
specified in 40 CFR 98.233(z).
3. Definition of Sub-Basin Category
a. Summary of Final Revisions
    The EPA is finalizing, as proposed, revisions to the definition of 
sub-basin category at 40 CFR 98.238. Specifically, we have defined sub-
basin category as ``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 five formation types: Oil, high permeability gas, 
shale gas, coal seam, or other tight gas reservoir rock. The 
distinction between high permeability gas and tight gas reservoirs 
shall be designated as follows: High permeability gas reservoirs with 
greater than 0.1 millidarcy permeability and tight gas reservoirs with 
less than or equal to 0.1 millidarcy permeability. Permeability for a 
reservoir type shall be determined by engineering estimate. Wells that 
produce only from high permeability gas, shale gas, coal seam, or other 
tight gas reservoir rock are considered gas wells; gas wells producing 
from more than one of these formation types shall be classified into 
only one type based on the formation with the most contribution to 
production as determined by engineering knowledge. All wells that 
produce hydrocarbon liquids (with or without gas) and do not meet the 
definition of a gas well in this sub-basin category definition are 
considered to be in the oil formation. All emission sources that handle 
condensate from gas wells in high permeability gas, shale gas, or tight 
gas reservoir rock formations are considered to be in the formation 
that the gas well belongs to and not in the oil formation.''
b. Summary of Comments and Responses
    The EPA received only supportive comments regarding these 
revisions, therefore, there are no changes from proposal to the final 
rule based on these comments.

B. Summary of Final Revisions to Calculation Methods and Reporting 
Requirements

    The final amendments described in this section include technical 
revisions and corrections to the calculation and reporting requirements 
of subpart W. In general, these revisions provide greater flexibility 
and potentially reduce burden to facilities, and they increase the 
clarity and congruency of the calculation and reporting requirements.
    These final amendments also include organizational revisions to the 
reporting requirements in 40 CFR 98.236. These revisions restructure 40 
CFR 98.236 to more closely align the reporting requirements with the 
calculation methods, clarify the data elements to be reported, and 
improve data utility. As proposed, we are reorganizing the reporting 
section by source type and, for each industry segment, listing which 
source types must be reported. We are also finalizing the addition of 
new data elements which would improve the quality of the data reported. 
These additional data elements are discussed in Section II.E of this 
preamble.
    The final amendments to the calculation and reporting requirements 
in subpart W are described in this section by emission source type 
(e.g., natural gas pneumatic device venting, acid gas removal vents, 
etc.). The amendments for each source type are followed by a summary of 
the major comments, if any, on those amendments and the EPA's 
responses. See the 2014 response to comment document in Docket Id. No. 
EPA-HQ-OAR-2011-0512 for a complete listing of all comments and the 
EPA's responses. Additional minor corrections, including minor edits to 
the calculation requirements of the final rule, are included in the 
memorandum, ``Minor Technical Corrections to Subpart W, Greenhouse Gas 
Reporting Rule: 2014 Revisions and Confidentiality Determinations for 
Petroleum and Natural Gas Systems; Final Rule'' in Docket Id. No. EPA-
HQ-OAR-2011-0512. Further information on the final changes to the 
reporting section may be found in the memorandum, ``Final Revisions to 
the Subpart W Reporting Requirements in the `Greenhouse Gas Reporting 
Rule: 2014 Revisions and Confidentiality Determinations for Petroleum 
and Natural Gas Systems; Final Rule' '' in Docket Id. No. EPA-HQ-OAR-
2011-0512.
1. Natural Gas Pneumatic Device Venting
a. Summary of Final Revisions
    We are finalizing revisions to Equation W-1 in 40 CFR 98.233(a) to 
sum the natural gas pneumatic device venting emissions across all types 
of pneumatic devices with minor revisions. We are revising the 
summation symbol to remove the ``i'' at the bottom of the summation 
symbol, which was inadvertently included with the summation symbol. 
This revision is needed to clarify that the summation is across 
different types of pneumatic devices (designated by ``t'') and not 
across different GHGs (designated by ``i''). We are finalizing 
revisions to 40 CFR 98.233(a)(1), (a)(2), and (a)(3) as proposed to 
simplify how ``Count<INF>t</INF>'' of Equation W-1 (total number of 
natural gas pneumatic devices of type ``t'') must be calculated each 
year as new devices are added. For the onshore petroleum and natural 
gas production industry segment, reporters continue to have the option 
in the first two reporting years to estimate ``Count<INF>t</INF>'' 
using engineering estimates. The EPA is also finalizing the reporting 
requirements with minor revisions from proposal. Specifically, the EPA 
is clarifying that certain reporting requirements in 40 CFR 
98.236(b)(1) and (2) should be reported by device type. These revisions 
clarify our original intent and address public comments received.
b. Summary of Comments and Responses
    Comment: One commenter noted that it appears that the EPA is 
removing the requirement to report information separately for each 
pneumatic controller type (continuous high bleed, continuous low bleed, 
intermittent bleed) and is instead requesting that all information from 
all three categories be lumped together in the proposed revisions to 40

[[Page 70357]]

CFR 98.236(b). According to the commenter, this seems like a backwards 
step in data collection and, given the current high interest in 
pneumatic controllers in oil and gas sector studies and by the EPA in 
technical white papers on the oil and gas sector, it seems illogical 
for the EPA to stop collecting this device-type-specific information. 
The commenter also noted a discrepancy between the proposed rule text 
at 40 CFR 98.236(b), which says ``you must report the information 
specified in paragraphs (b)(1) through (b)(4) of this section'' while 
the memorandum entitled ``Revisions to the Subpart W Reporting 
Requirements as proposed in the Greenhouse Gas Reporting Rule: 
Revisions and Confidentiality Determinations for Petroleum and Natural 
Gas Systems; Proposed Rule'' says ``you must report the information 
specified in paragraphs (b)(1) through (b)(4) of this section for each 
device type.''
    Response: The EPA agrees with the commenter that certain reporting 
elements in 40 CFR 98.236(b) should be reported by device type. We 
removed the phrase ``for each device type'' from paragraph 40 CFR 
98.236(b) prior to proposal because the reporting elements in 
paragraphs (b)(3) and (b)(4) are aggregate emissions across the three 
device types (``. . . combined, calculated using Equation W-1''). It 
was not our intent to collect aggregated data regarding the number of 
pneumatic devices. For example, the reporting element in paragraph 40 
CFR 98.236(b)(2) specifically indicates that the reporting element is 
``T<INF>t</INF>'' in Equation W-1, which is specific to the type of 
pneumatic device. To address this issue, we are revising paragraphs 
(b)(1)(i), (b)(1)(ii)(A) and (B), and (b)(2) to indicate that these 
reporting elements must be reported for each type of pneumatic device. 
These data will allow the EPA to verify the aggregate emissions 
calculated using Equation W-1 and perform more detailed analysis of 
emissions by device type.
2. Acid Gas Removal Vents
a. Summary of Final Revisions
    For acid gas removal (AGR) vents, we are finalizing several 
technical revisions as proposed and adding minor clarifying revisions 
to address public comments received. We are finalizing minor clarifying 
edits to 40 CFR 98.233(d) as proposed to clearly label each calculation 
method and to clarify provisions by providing references to equations 
where appropriate. We are also finalizing the proposed revisions to the 
parameters ``Vol<INF>CO2</INF>'' in Equation W-3 and parameters 
``Vol<INF>I</INF>'' and ``Vol<INF>O</INF>'' in Equation W-4A and W-4B 
to clarify that the volumetric fraction used should be the annual 
average. As proposed, we are specifying in 40 CFR 98.233(d)(8) that 
reporters may use sales line quality specifications for CO<INF>2</INF> 
in natural gas only if a continuous gas analyzer is not available.
    In response to public comments, we are making four minor 
corrections and clarifying revisions to the calculation and reporting 
requirements for AGR units. First, we are removing an errant proposed 
requirement in 40 CFR 98.236(d)(10) to calculate annual mass emissions 
``at standard conditions.'' Second, in response to a comment that the 
sub-basin identification (ID) reporting requirement in 40 CFR 
98.236(d)(1)(vi) is unclear when an AGR unit treats gas from wells in 
more than one sub-basin, we are revising the data element to require 
reporting of the sub-basin ID ``that best represents the wells 
supplying gas to the unit.'' Third, in response to comments on the 
proposed missing data procedures for AGR units (proposed 40 CFR 
98.235(a), we are adding the clause ``. . . for each quarter that the 
AGR unit is operating . . .'' in paragraphs 40 CFR 98.233(d)(6), (7), 
and (8)(ii) to clarify that quarterly samples are only required to be 
collected for quarters when the unit is operated. Fourth, in response 
to a comment on the proposed confidentiality determinations for AGR 
units, we are correcting the reporting requirements for the amount of 
CO<INF>2</INF> from AGR units that is recovered and transferred outside 
the facility (40 CFR 98.236(d)(1)(iv)); the requirement to report this 
quantity ``under subpart PP'' was inadvertently omitted from the 
proposed rule. See Section II.C of this preamble for additional 
discussion of changes to the missing data procedures related to AGR 
units, and see Section III.B of this preamble for additional discussion 
of the confidentiality determination for the data element related to 
reporting the amount of CO<INF>2</INF> recovered and transferred 
outside the facility.
b. Summary of Comments and Responses
    The EPA did not receive any major comments on the proposed 
revisions to the calculation and reporting requirements for AGR units. 
See the 2014 response to comment document in Docket Id. No. EPA-HQ-OAR-
2011-0512 for a complete listing of all comments and responses.
3. Dehydrators
a. Summary of Final Revisions
    The EPA is clarifying that Calculation Method 1 in 40 CFR 
98.236(e)(1) is not applicable to desiccant dehydrators. We proposed 
this clarification by including the word ``absorbent'' to describe the 
types of dehydrators for which Calculation Method 1 applies. We 
received comment that the term ``absorbent dehydrators'' was not a 
common term used by industry and was not defined in the rule. We are 
finalizing amendments to both 40 CFR 98.236(e)(1) and (e)(3) to clarify 
our original intent that Calculation Method 1 is applicable to glycol 
(liquid absorbent) dehydrators and that emissions from desiccant 
dehydrators of any size should be determined using Calculation Method 3 
in 40 CFR 98.236(e)(3). We are finalizing revisions as proposed to 
clarify that the 0.4 million standard cubic feet (MMscf) per day 
throughput relates to the natural gas throughput of the dehydrator for 
determining the applicability of Calculation Method 1. We are 
finalizing revisions to clarify the calculation methods for dehydrators 
to provide for the adjustment of emissions vented to a vapor recovery 
system as proposed. We are finalizing clarifications to the calculation 
of emissions when vented to a flare with minor revisions to those 
proposed. Specifically, we are including reference to 40 CFR 
98.233(e)(5) in paragraph (e)(6)(i) in the event a portion of the 
dehydrator vent emissions are recovered and a portion are vented to a 
flare. Finally, we are finalizing, as proposed, clarification to the 
reporting requirements in 40 CFR 98.236(e)(2) for glycol dehydrators 
with an annual average daily natural gas throughput less than 0.4 MMscf 
per day to account for scenarios in which a dehydrator may be vented to 
more than one emission point (e.g., with one vent routed to a flare and 
one vent routed to vapor recovery).
b. Summary of Comments and Responses
    Comment: One commenter objected to the term ``absorbent 
dehydrator.'' The commenter stated that this is not a term used by 
industry, is not defined in the rule, and may cause confusion with 
desiccant dehydrator requirements as they use an absorbent. The 
commenter recommended the term ``glycol dehydrator'' be used rather the 
proposed ``absorbent dehydrator'' term.
    Response: The EPA agrees with the commenter in that desiccant 
dehydrators use a solid absorbent, so the term ``absorbent dehydrator'' 
is

[[Page 70358]]

ambiguous. We considered amending the descriptive clause to ``liquid 
absorbent'' dehydrators; however, based on available information, 
liquid absorbent systems use glycol and the term glycol dehydrators is 
already used to describe the dehydrators for which Calculation Method 2 
is applicable. Therefore, to clarify our original intent, we are 
replacing the proposed ``absorbent dehydrator'' term with the term 
``glycol dehydrator'' in the first sentence in 40 CFR 98.236(e)(1). We 
are also revising the first sentence in 40 CFR 98.233(e)(3) to begin as 
follows: ``For dehydrators of any size that use desiccant, you must 
calculate emissions . . .'' These edits clarify our original intent and 
address the commenter's concerns regarding the proposed ``absorbent 
dehydrator'' term.
4. Well Venting for Liquids Unloading
a. Summary of Final Revisions
    As proposed, the EPA is revising the calculation and reporting 
requirements for well venting from liquids unloading. These revisions 
include allowances for annualizing venting data for facilities that 
calculate emissions using a recording flow meter (Calculation Method 1 
at 40 CFR 98.233(f)(1)); revisions to Calculation Method 1 at 40 CFR 
98.233(f)(1) and reporting requirements at 40 CFR 98.236 to separate 
the calculation and reporting of emissions from wells that have plunger 
lifts and wells that do not have plunger lifts; and clarification of 
the term ``SP<INF>p</INF>'' in Equation W-8 (40 CFR 98.233(f)(2)) to 
specify that, if casing pressure is not available for each well, 
reporters may determine the casing pressure using a ratio of the casing 
pressure to tubing pressure from a well in the same sub-basin where the 
casing pressure is known.
b. Summary of Comments and Responses
    The EPA received supportive comments for the proposed revisions and 
did not receive major comments opposing the proposed revisions to the 
calculation and reporting requirements for well venting from liquids 
unloading. The EPA is not making any changes to the proposed amendments 
in the final rule as a result of public comments. See the 2014 response 
to comment document in Docket Id. No. EPA-HQ-OAR-2011-0512 for a 
complete listing of all comments and responses.
5. Gas Well Completions and Workovers
a. Summary of Final Revisions
    The EPA is finalizing several definitions pertinent to gas well 
completions and workovers. The EPA is finalizing amendments to 40 CFR 
98.238 to add definitions for ``reduced emissions completion'' and 
``reduced emissions workover'' with minor revisions from the proposed 
definitions. The proposed definitions of these terms implied that there 
would be no direct releases to the atmosphere. Public comments 
indicated that this phrase was too restrictive and we have revised the 
definition to clarify that a ``reduced emissions completion'' or a 
``reduced emissions workover'' will have de minimis venting to the 
atmosphere and may have short periods of flaring. The EPA is finalizing 
as proposed the definition of ``well completions'' in 40 CFR 98.6 of 
subpart A to delete the term ``re-fracture'' as this term applies to an 
already producing well and is considered a well workover, not a well 
completion, for the purposes of part 98.
    We are also revising the reporting requirements for gas well 
completions and workovers to differentiate between different well type 
combinations in each sub-basin category, as proposed. A well type 
combination is a unique combination of the following factors: Vertical 
or horizontal, with flaring or without flaring, and reduced emissions 
completion (REC)/workover or no REC/workover.
    As proposed, we are revising Equation W-10A, the time variable 
``T<INF>p</INF>'' in Equation W-10A and W-10B, the calculation section 
at 40 CFR 98.233(g) and (h), and Equation W-13 in 40 CFR 98.233(h) and 
adding new Equation W-13B in 40 CFR 98.233(h). We are revising 40 CFR 
98.233(g)(1) and (g)(2) as proposed to clarify measurement 
requirements. We are also finalizing revisions as proposed for the 
parameter ``PR<INF>s,p</INF>'' in Equations W-10A and W-10B and 
Equation W-12 to clarify that the first 30 day average production flow 
rate is the average taken after completions of newly drilled gas wells 
or workovers.
    The final rule also corrects two errors in the proposed reporting 
requirements in 40 CFR 98.236(g)(5)(i) so that the final reporting 
requirements are consistent with the variables used in the revised 
Equation W-10A. First, the final rule uses the term ``flowback'' 
instead of ``backflow.'' Second, instead of requiring reporting of the 
``cumulative backflow time,'' which is an artifact of requirements in 
the subpart W 2010 final rule, the final 40 CFR 98.236(g)(5)(i) 
requires reporting of the cumulative gas flowback time from when gas is 
first detected until sufficient quantities are present to enable 
separation (``T<INF>p,i</INF>'' in Equation W-10A) and the cumulative 
flowback time after sufficient quantities of gas are present to enable 
separation (``T<INF>p,s</INF>'' in Equation W-10A).
b. Summary of Comments and Responses
    This section summarizes the major comments and responses related to 
the proposed amendments to gas well completions and workovers. See the 
2014 response to comment document in Docket Id. No. EPA-HQ-OAR-2011-
0512 for a complete listing of all comments and responses.
    Comment: Two commenters asserted that the proposed rule 
significantly increases the burden by expanding the definition of well 
type in 40 CFR 98.233(g)(2) to differentiate between the scenarios of 
with or without flaring and with REC/workover or without REC/workover. 
The commenters stated that expanding the well type definition increases 
the maximum number of measurement combinations to be reported from 10 
(five formation types and two well types) to 40 (five formation types 
and eight well types). Additionally, one commenter stated that it is 
difficult for reporters to identify and plan for which wells to 
measure, because the reporter cannot predict whether a well will need a 
flare or a vent until after beginning the actual flowback. The 
commenter noted that implementation of 40 CFR part 60, subpart OOOO, 
will sharply reduce, but not eliminate, the number of flowbacks where 
gas is not flared and/or RECs are not performed; therefore, these 
scenarios will still be present and would need to be measured. Another 
commenter requested that the EPA reconsider splitting the reporting and 
measurement categories for well completions and workovers because 
reporters have established data collection and management systems based 
on the existing well types. The commenter stated that the proposed 
changes would double or quadruple the number of required measurements 
or calculations, input data management, and reporting requirements. One 
commenter supported the changes in the data collection, stating that 
disaggregated data will help distinguish emissions by well type and 
control technology, facilitate a deeper understanding of the factors 
affecting oil and gas sector emissions, and improve the data for use in 
the Inventory of U.S. Greenhouse Gas Emissions and Sinks.
    Response: In the final rule, the EPA is maintaining the requirement 
to measure emissions separately per sub-basin and well type combination 
instead of aggregations of these distinct operational practices. As 
some commenters noted, the disaggregated

[[Page 70359]]

data will improve data quality for emissions from gas well completions 
and workovers with hydraulic fracturing. We disagree with some of the 
commenters that the new requirements will impose a significant 
additional burden on reporters. The EPA expects that operational 
practices will generally be the same in a given sub-basin and considers 
it unlikely that a reporter would conduct drilling activities for a 
given sub-basin in all the different well type combinations of vertical 
or horizontal, with flaring or without flaring, and REC/workover or no 
REC/workover. For example, gas well hydraulic fracturing focused on 
horizontal drilling in a shale gas formation in a county using reduced 
emissions completions and flaring would constitute one category. As one 
commenter noted, owners or operators of gas wells must comply with 40 
CFR part 60, subpart OOOO. While some of the other categories may be 
present for some reporters, compliance with subpart OOOO will result in 
most reporters being in the category of reduced emissions completions 
with flaring. Additionally, subpart W provides flexibility by allowing 
reporters to determine flowback rates using engineering calculations 
provided in Equations W-11A or W-11B.
    Comment: One commenter asked whether the proposed definition for 
REC was intended to be consistent with the definition used in 40 CFR 
part 60, subpart OOOO. The commenter requested that if this is the 
EPA's intent, then the definition should be expanded to clarify that 
there may be some degree of venting during some portion of the flowback 
period. The commenter stated that the proposed Part 98 definition does 
not acknowledge that flowback is vented, and that the definition should 
include clarification. The commenter noted that, as proposed, the 
definition of ``reduced emissions completion'' would result in no RECs 
reported due to the phrase ``no direct release to the atmosphere.'' In 
addition, the commenter stated that the subpart W definition does not 
provide for flaring to occur on wells with RECs. The commenter 
requested that the EPA modify the definition for reduced emission 
completions to harmonize with the revised calculation approach for 
completions and workovers with hydraulic fracturing, which addresses 
the small amount of venting during initial flowback and provides for 
flaring associated with well completions and workovers.
    Response: We agree with the commenter that there can be a small 
amount of venting during the initial flowback, and that in some 
situations flaring is conducted. In the final rule we are revising the 
definitions of ``reduced emissions completion'' and ``reduced emissions 
workover'' to clarify the venting and flaring activities that may 
occur.
6. Blowdown Vents
a. Summary of Final Revisions
    The EPA is finalizing, with some modifications, the proposed 
revisions to include a compressibility term in Equations W-14A and W-
14B for calculating emissions from blowdown vents and also in Equations 
W-33 and W-34 to convert volumetric emissions at actual conditions to 
standard conditions. The EPA proposed to allow reporters to use a 
compressibility factor of 1 under certain temperature and pressure 
conditions, otherwise a site-specific compressibility factor must be 
calculated and used for each blowdown event or conversion to standard 
conditions. Commenters indicated that these requirements posed a 
significant burden on reporters without significantly improving the 
calculated emissions. After considering the public comments, we are 
finalizing the inclusion of the compressibility term in Equations W-
14A, W-14B, W-33 and W-34, but we are optionally allowing reporters to 
use a default value of 1 or a site-specific compressibility factor 
regardless of the temperature and pressure conditions.
    The EPA is finalizing the equipment type categories and the 
reporting requirements for blowdown vents with minor modifications to 
those proposed. In the final rule, we have incorporated the term 
``equipment or event type'' rather than simply ``equipment type'' where 
appropriate to include reference to emergency shutdown blowdown 
activities. We clarified the ``emergency shutdown'' category to include 
all emergency shutdown blowdown emissions regardless of equipment type. 
We also revised the category proposed as ``station piping'' to be 
``facility piping'' to be more applicable to the onshore natural gas 
processing and liquefied natural gas (LNG) import and export equipment 
industry segments; we also clarified the distinction between ``facility 
piping'' and ``pipeline venting.'' We also revised the category 
proposed as ``all the other blowdowns greater than or equal to 50 cubic 
feet'' category to ``all other equipment with a physical volume greater 
than or equal to 50 cubic feet'' to clarify it is the physical volume 
of the equipment, not the blowdown volume (converted to standard 
conditions), to which the 50 cubic feet threshold applies.
    The EPA is also adding an optional calculation method (40 CFR 
98.233(i)(3)) for blowdown emissions for situations where a flow meter 
is in place and including associated reporting requirements in 40 CFR 
98.236. If a flow meter is in place to measure emissions, the emissions 
are reported on a facility basis and would not be aggregated by 
emission type per 40 CFR 98.236(i)(2). These revisions are finalized 
with minor revisions to clarify that reporters may use flow meters for 
some blowdown stacks and use equipment or event type calculations for 
other blowdown vent stacks at the same facility.
b. Summary of Comments and Responses
    This section summarizes the major comments and responses related to 
blowdown vent emissions. See the 2014 response to comment document in 
Docket Id. No. EPA-HQ-OAR-2011-0512 for a complete listing of all 
comments and responses.
    Comment: Three commenters opposed the proposed mandatory use of a 
compressibility factor (Z) in equations W-14A, W-14B, W-33, and W-34. 
The commenters stressed that requiring the calculation of Z places a 
significant burden on industry without producing a substantive benefit 
in terms of increased data and emissions accuracy. One commenter also 
claimed that the inclusion of a mandatory compressibility factor would 
result in inconsistencies with prior year reports. The three commenters 
supported allowing the optional use of a compressibility factor that 
would not impose new burdens but would provide greater flexibility to 
reporters. One commenter asserted that some companies already use a 
compressibility term in their blowdown emission calculations, and some 
reporters have existing company algorithms and programs used to track 
blowdown venting and calculations emissions that account for 
compressibility. Another commenter stated that mandating the use of the 
compressibility factor in the blowdown vent calculations would require 
changes to these existing systems and increase implementation costs. 
The commenters argued that the EPA has not considered or justified 
these costs.
    One commenter noted that the proposed conditions for using the 
compressibility term would require the calculation of Z for nearly all 
equipment blowdown calculations at transmission and storage facilities. 
The commenter stated that transmission pipelines

[[Page 70360]]

typically operate in the range of about 500 to about 1,000 pounds per 
square inch gauge (psig), therefore the proposed rule would require a 
calculated value of Z for most, if not all, transmission segment 
blowdown emission calculations. One commenter asserted that the EPA has 
not demonstrated that inclusion of the compressibility factor will 
significantly or cost-effectively reduce the overall uncertainty of the 
blowdown vent emission estimates. The commenter disagreed with the 
EPA's assessment of uncertainty and argued that the potential 
uncertainty introduced by failure to use a compressibility factor is 
only on the order of 10 percent.
    Response: The EPA evaluated the commenters' concerns and is 
changing the requirements from proposal. We have revised the final rule 
to allow reporters the option to use a default compressibility factor 
or a site-specific factor instead of being required to use a site 
specific factor for specific temperature and pressure ranges. We 
maintain that the accuracy of the emission calculation is improved if a 
compressibility factor is included. However, we also recognize the 
commenters' concern that, for many reporters, programs and algorithms 
are already in place that do not include the site-specific factor in 
the calculations, and any revision would incur additional burden and 
cost in updating the programs and algorithms. We agree with the 
commenters' suggestion to allow the optional use of site-specific 
compressibility factors. This approach allows for improved accuracy for 
facilities that have processes in place to determine site-specific 
compressibility factors, while not increasing the burden to facilities 
that do not. Therefore, in this final rule, reporters may use either a 
default value of 1 or a site-specific compressibility factor regardless 
of the temperature or pressure range of the system.
    Comment: Several commenters supported the use of equipment type 
categories for aggregating and reporting blowdown emissions, but one of 
these commenters stated that the rule should allow reporters to 
optionally report emissions by unique blowdown volumes. Two commenters 
requested clarification of several of the blowdown categories. First, 
the commenters recommended that the seven categories be called 
``equipment/event types'' to more accurately describe the ``emergency 
shutdown'' category. The commenters suggested that the EPA clarify that 
emergency shutdown blowdown emissions should always be categorized 
under the ``emergency shutdown'' category, regardless of the type of 
equipment that is blown down and that the EPA should clarify the 
distinction between ``station piping'' (i.e., within the compressor 
station boundary) and ``pipeline venting'' (i.e., pipe external to the 
compressor station that is vented within the station boundary). 
Finally, the commenters recommended that the category ``all other 
blowdowns greater than or equal to 50 cubic feet'' should be ``all 
other equipment with a physical volume greater than or equal to 50 
cubic feet.'' One commenter also recommended that the EPA include 
clarification that, if a blowdown event results in emissions across 
multiple equipment types and the emissions cannot be apportioned to the 
different equipment types, then the reporter may categorize the 
emissions to the equipment type that represents the largest portion of 
the emissions from the blowdown event.
    Response: The EPA disagrees with the one commenter's suggestion to 
make the blowdown categories optional. The EPA, as well as other 
commenters, have agreed that the requirement reduces burden and 
simplifies the rule. Providing the categories as optional to reporters 
would result in inconsistencies in the reported data and may limit the 
EPA's ability to compare and review information between reporters. The 
EPA agrees with the commenters that further clarification would be 
helpful regarding the categories for reporting blowdown emissions. In 
the final rule, we have incorporated the term ``equipment or event 
type'' when referring to all seven categories to more clearly include 
emergency shutdown blowdown activities. We also revised the emergency 
shutdown category to indicate that this category includes emergency 
shutdown blowdown emissions regardless of equipment type. In reviewing 
the commenters' suggested clarification of station piping and pipeline 
venting, we found that the nomenclature was very specific to onshore 
natural gas transmission compression industry segment, but blowdown 
emissions may also be reported for the onshore natural gas processing 
and LNG import and export equipment industry segments. Therefore, we 
have revised the ``station piping'' category to be ``facility piping.'' 
We have also clarified that station piping refers to ``piping within 
the facility boundary other than physical volumes associated with 
distribution pipelines'' and that pipeline venting refers to ``physical 
volumes associated with distribution pipelines vented within the 
facility boundary.'' We also revised the category proposed as ``all the 
other blowdowns greater than or equal to 50 cubic feet'' category to 
``all other equipment with a physical volume greater than or equal to 
50 cubic feet'' to clarify it is the physical volume of the equipment, 
not the blowdown volume (converted to standard conditions), to which 
the 50 cubic feet threshold applies. Finally, we are incorporating the 
commenter's suggestion to specify that if a blowdown event results in 
emissions across multiple equipment types and the emissions cannot be 
apportioned to the different equipment types, then the reporter may 
categorize the emissions to the equipment type that represents the 
largest portion of the emissions from the blowdown event. We note that 
the phrase ``equipment type'' is correct here because this assignment 
would only be necessary if the blowdown event is not associated with an 
emergency shutdown.
    Comment: One commenter recommended that the rule should clearly 
indicate that both the method for determining emissions from blowdown 
vent stacks using a flow meter and the method for determining emissions 
from blowdown vent stacks according to equipment type can be used for 
different blowdown emission sources at a given facility. The commenter 
also recommended that the rule clearly indicate that, when a flow meter 
is used, that it is not necessary to categorize emissions by equipment 
type.
    Response: The EPA has evaluated the commenter's suggestions and 
agrees that the changes would clarify the rule. In the final rule, the 
EPA is clarifying in 40 CFR 98.233(i) that the facility may use the 
equipment/event type method for some blowdown vent stacks and use the 
flow meter for other blowdown vent stacks. We are also clarifying the 
reporting requirements in 40 CFR 98.236(i) to accommodate reporting 
when both calculation methods are used. Facility owners or operators 
must report by the equipment/event type categories for the blowdown 
stack vents that use the equipment or event type calculation method and 
they must report the cumulative emissions for all blowdown vent stacks 
that use flow meters to determine blowdown emissions.
    Comment: Two commenters recommended a change to the emissions 
calculations for blowdown volumes. The commenters asserted that the 
current order of calculations for blowdown vents is incorrect. The 
commenters noted that gases in the same equipment can have very 
different compositions, and that the

[[Page 70361]]

presumptions in the proposed rule, which would apply the same gas 
composition to all equipment types, would not represent actual 
emissions. The commenters suggested that emissions be summed into 
equipment types after applying applicable gas compositions (i.e., after 
application of 40 CFR 98.233(u) and (v)) to each individual unique 
physical volume.
    Response: The EPA evaluated the order of the emissions calculations 
for blowdown volumes presented in the proposed rule and agrees that, 
for certain industry segments, the order of calculations would 
introduce inaccuracies and create confusion over which gas compositions 
to use in the calculation. For certain industry segments, such as 
onshore natural gas transmission compression and LNG import and export 
equipment, the order of the summation does not introduce inaccuracies 
because the gas composition is expected to be the same in all equipment 
at the facility. Therefore, in the final rule, the EPA has revised the 
order of calculations to first require that the CH<INF>4</INF> and 
CO<INF>2</INF> volumetric and mass emissions be calculated for each 
physical volume (e.g., the inlet volume) associated with each equipment 
or event category. The total annual CH<INF>4</INF> and CO<INF>2</INF> 
mass emissions must then be calculated for each equipment or event 
category by summing the CH<INF>4</INF> and CO<INF>2</INF> mass 
emissions for all unique physical volumes associated with the equipment 
or event category. These changes allow reporters to apply the 
appropriate gas composition for each physical volume prior to 
aggregating emissions by equipment or event type. However, the final 
rule also allows reporters in the onshore natural gas transmission 
compression and LNG import and export equipment sectors to elect to sum 
their natural gas volumetric emissions first and then apply composition 
data to determine CH<INF>4</INF> and CO<INF>2</INF> volumetric and mass 
emissions since the composition data is expected to be the same for all 
volumes.
7. Onshore Production Storage Tanks
a. Summary of Final Revisions
    We are finalizing revisions to the introductory text at 40 CFR 
98.233(j) with minor modifications to those proposed to clarify the 
calculation methods that must be used for onshore production storage 
tanks. We are also finalizing amendments to 40 CFR 98.233(j)(6), with 
minor modifications to those proposed. We received comment that the 
proposed revisions to 40 CFR 98.233(j)(6) appeared to expand the 
applicability of this requirement to all tanks rather than tanks with 
an annual average daily throughput of 10 barrels per day or more. This 
was an inadvertent error. Therefore, we are clarifying in this final 
rule, both in the 40 CFR 98.233(j) introductory text and 40 CFR 
98.233(j)(4), that you must calculate emissions from dump valve leakage 
only if you use Calculation Method 1 or Calculation Method 2. We are 
also revising the parameter ``E<INF>n</INF>'' in Equation W-16 from the 
proposed rule to remove the reference to Calculation Method 3, which 
was erroneously included in the proposed rule.
    In reviewing the comments received on the proposed rule, we noted 
inconsistencies in Calculation Method 2 between the calculation method 
described in 40 CFR 98.233(j)(2) and the implementation of that method 
as described in paragraphs (j)(2)(i) and (j)(2)(ii). In the proposed 
rule, we attempted to consolidate within Calculation Method 2 the 
calculation methods for storage tanks receiving oil directly from the 
production well without passing through a wellhead separator and 
storage tanks receiving oil from a wellhead separator. The introductory 
text in the proposed paragraph (j)(2) references composition at the 
separator temperature and pressure, which is appropriate if there is a 
separator, but it also requires use of either paragraphs (j)(2)(i) and 
(j)(2)(ii), both of which describe composition at the wellhead, which 
is only appropriate if there is not a separator. Therefore, we are 
revising Calculation Method 2 to more clearly designate that the 
composition at separator temperature and pressure should be used if the 
storage tank receives oil after passing through a separator and to use 
the wellhead composition if the tank receives oil directly from the 
well.
    We are finalizing the amendments to the reporting requirements for 
onshore production storage tanks as proposed (except as described in 
Section III.A. of this preamble).
b. Summary of Comments and Responses
    This section summarizes the major comments and responses related to 
onshore production storage tanks. See the 2014 response to comment 
document in Docket Id. No. EPA-HQ-OAR-2011-0512 for a complete listing 
of all comments and responses.
    Comment: Two commenters objected to proposed revisions in 40 CFR 
98.233(j)(6) that appeared to expand the reporting of emissions from 
stuck dump valves to all tanks, including those with throughput less 
than 10 barrels per day. One commenter considered this expansion in 
reporting to be burdensome and costly, given the investments already 
made to manage data collection in response to the original rule.
    Response: We agree with the commenters that the calculation methods 
in (j)(6), as proposed, would apply to all storage tanks that have dump 
valves that are not closing properly, while Equation W-16 previously 
did not consider emissions from storage tanks with throughput less than 
10 barrels per day. It was not the EPA's intent to require reporting of 
emissions from stuck dump valves to storage tanks with a throughput 
less than 10 barrels per day. Therefore, we are clarifying in 40 CFR 
98.233(j) and 40 CFR 98.233(j)(6) that you must calculate emissions 
from dump valve leakage only if you use Calculation Method 1 or 
Calculation Method 2 (applicable for storage tanks with a throughput of 
10 barrels per day or more). We are also revising the parameter 
``E<INF>n</INF>'' in Equation W-16 from the proposed rule to remove the 
reference to Calculation Method 3, which was erroneously included in 
the proposed rule.
8. Transmission Storage Tanks
a. Summary of Final Revisions
    We are finalizing revisions to the provisions for transmission 
storage tanks in 40 CFR 98.233(k) with minor modification to those 
proposed to reorder the calculations in response to comments received. 
We are finalizing the amendments to the reporting requirements for 
transmission storage tanks with minor revisions to correct section 
number references to the reordered paragraphs in 40 CFR 98.233(k) and 
other editorial revisions in response to comments received.
b. Summary of Comments and Responses
    Comment: One commenter noted that the order of the requirements in 
40 CFR 98.233(k) were confusing and should be changed to match the 
actual calculation progression. The commenter noted that cross-
references in the reporting section at 40 CFR 98.236(k) will need to be 
revised if the calculation order is revised.
    Response: We reviewed the proposed calculation order and agree with 
the commenter that the calculation order should be clarified. We moved 
the calculations for determining annual emissions proposed at 40 CFR 
98.233(k)(2)(iii) and (k)(2)(iv) to a new paragraph 40 CFR 98.233(k)(4) 
and renumbered the flare calculation

[[Page 70362]]

paragraph from (k)(4) to (k)(5). We made corresponding revisions to the 
cross-references in 40 CFR 98.236(k).
9. Associated Gas Venting and Flaring
a. Summary of Final Revisions
    In order to improve data quality and avoid over-estimating 
emissions, the EPA is finalizing revisions to Equation W-18 (40 CFR 
98.233(m)(3)) to add the term ``SG<INF>p,q</INF>'' as proposed to 
account for situations where part of the associated gas from a well 
goes to a sales line while another part of the gas is flared or vented. 
The EPA is not finalizing the addition of the proposed term 
``ERE<INF>p,q</INF>'' for emissions reported under other sources, 
because the overlap in emissions reported elsewhere has been determined 
by the EPA to be negligible and because commenters have identified 
these emissions as potentially burdensome to track. The EPA is also 
finalizing revisions as proposed to the term ``GOR<INF>p,q</INF>'' and 
the emission result ``E<INF>s,n</INF>'' in Equation W-18 to specify 
that the gas-to-oil ratio (GOR) and the result of the calculation are 
calculated at standard conditions rather than actual conditions.
    The EPA also proposed to add a definition for the term ``Associated 
gas venting or flaring'' to clarify what is included in this source. We 
are finalizing these amendments as proposed.
b. Summary of Comments and Responses
    This section summarizes the major comments and responses related to 
associated gas venting and flaring. See the 2014 response to comment 
document in Docket Id. No. EPA-HQ-OAR-2011-0512 for a complete listing 
of all comments and responses.
    Comment: One commenter disagreed with the addition of the term 
``ERE<INF>p,q</INF>'' to equation W-18 for ``emissions reported 
elsewhere''. The commenter stated that including the term would 
significantly increase the burden, provide little increase in the 
accuracy of reported emissions, and, due to the difference in methods 
used to account for the equation parameters, may result in the 
calculation of negative volumes. The commenter recommended removing the 
term and revising the definition of the summation term for the equation 
to indicate that it applies to associated gas not reported elsewhere, 
consistent with the new definition for associated gas venting and 
flaring.
    Response: The EPA included the term ``ERE<INF>p,q</INF>'' in 
Equation W-18 of the proposed rule to harmonize with the proposed 
definition of ``associated gas venting or flaring,'' which was defined 
to exclude venting or flaring resulting from activities that are 
reported elsewhere, such as tank venting. Equation W-18 calculates 
associated gas emissions based on the gas-to-oil ratio (GOR) and volume 
of oil produced during the venting or flaring period. After considering 
the public comments, we determined that the potential for double-
counting emissions using Equation W-18 with emissions reported 
elsewhere was minimal, particularly given the proposed definition of 
``associated gas venting or flaring.'' For example, the EPA determined 
that the emissions as calculated using Equation W-18 are not expected 
to include or double-count emissions from onshore production storage 
tanks receiving oil from a separator at the wellhead. If onshore 
production storage tanks receive oil directly from the wellhead, these 
emissions are accounted for in the provisions for onshore production 
storage vessels, and these emissions would not constitute ``associated 
gas venting or flaring'' as defined in the proposal. Therefore, we 
concluded that the ``ERE<INF>p,q</INF>'' term was not needed in 
Equation W-18. We are revising the proposed Equation W-18 to remove the 
``ERE<INF>p,q</INF>'' term, and we are finalizing the definition of 
``associated gas venting or flaring'' as proposed.
10. Flare Stack Emissions
    The EPA is finalizing revisions as proposed to simplify and clarify 
the calculation requirements for flare stack emissions in order to 
improve the accuracy of the collected data. As proposed, we are 
amending the calculation method for emissions from a flare stack to 
revise the calculations to standard conditions and to account for the 
fraction of emissions that are not combusted when sent to an unlit 
flare. The fraction of feed gas sent to an unlit flare is determined by 
using engineering estimates and process knowledge.
    The EPA is finalizing amendments, as proposed, to include flare 
stack emissions to the list of sources for which emissions must be 
calculated for the onshore natural gas transmission compression, 
underground natural gas storage, LNG storage, and the LNG import and 
export equipment industry segments. The EPA did not receive major 
comments on these provisions and is not making any changes to the final 
rule as a result of public comments. See the 2014 response to comment 
document in Docket Id. No. EPA-HQ-OAR-2011-0512 for a complete listing 
of all comments and responses.
11. Centrifugal and Reciprocating Compressors
a. Summary of Final Revisions
    The EPA is finalizing amendments to the monitoring requirements for 
compressors with revisions to the proposed requirements. First, we are 
finalizing changes to the centrifugal and reciprocating compressor 
calculation sections (40 CFR 98.233(o) and (p)) to allow for the 
measurement of combined volumetric emissions from a manifolded group of 
compressor sources. In the proposed rule, reporters that had manifolded 
compressors were required to take at least three measurements per year 
and report the average of the measurements. In this final rule, we are 
requiring reporters to take a single measurement per year from 
manifolded compressors, which is commensurate with the measurement 
frequency for compressors that are not part of a manifold group of 
compressors. In the proposed rule, measurements from manifolded 
compressors were required to be taken before emissions are comingled 
with other non-compressor emission sources. We received comments that 
this requirement would often require new sampling ports in unsafe 
locations. In this final rule, we are changing this requirement to read 
as follows: ``Measure at a single point in the manifold downstream of 
all compressor inputs and, if practical, prior to comingling with other 
non-compressor emission sources''.
    The proposed rule inadvertently removed the use of acoustic device 
measurement for blowdown valve leakage for centrifugal and 
reciprocating compressors. It was not the EPA's intent to remove these 
provisions. As noted in the subpart W 2010 final rule and reiterated by 
commenters, the EPA has allowed the use of acoustic device measurement 
to address concerns regarding safety or inaccessibility issues for some 
vent measurements. As a result, we are allowing for quantification of 
emissions due to leaks from compressor blowdown valve leakage using an 
acoustic leak detection device. In this final rule, we are allowing the 
use of screening methods in 40 CFR 98.234(a) to determine whether 
quantitative emissions measurements are needed. We are finalizing the 
proposed reporting requirements for individual compressors and for 
manifolded compressors with minor changes intended to improve clarity.
    We are also finalizing four definitions in 40 CFR 98.238 to support 
the addition of the calculation method for manifolded vents. We are 
finalizing the

[[Page 70363]]

definitions of ``compressor mode,'' ``manifolded compressor source,'' 
and ``manifolded group of compressor sources'' as proposed. The EPA 
received comments asserting that the fourth proposed definition for 
``compressor source'' was unnecessarily vague. To address this concern, 
we are finalizing a revised definition of ``compressor source'' that 
includes detailed information regarding the types of emissions sources 
covered within the definition. We are finalizing the definition for 
``compressor source'' to mean ``the source of certain venting or 
leaking emissions from a centrifugal or reciprocating compressor. For 
centrifugal compressors, ``source'' refers to blowdown valve leakage 
through the blowdown vent, unit isolation valve leakage through an open 
blowdown vent without blind flanges, and wet seal oil degassing vents. 
For reciprocating compressors, ``source'' refers to blowdown valve 
leakage through the blowdown vent, unit isolation valve leakage through 
an open blowdown vent without blind flanges, and rod packing 
emissions.''
    For compressors that are routed to an operational flare, we are 
finalizing revisions as proposed to allow operators to calculate and 
report emissions with other flare emissions. As we proposed, reporters 
must still report certain compressor-related activity data for each 
compressor that is routed to an operational flare (as provided for in 
40 CFR 98.236(o)(1) and (o)(2) and (p)(1) and (p)(2)).
    The EPA is also finalizing several changes with regard to mode-
specific measurements as proposed. We are finalizing as proposed the 
revisions to the requirements to measure each compressor in the not-
operating-depressurized (NOD) mode at least once in any 3 consecutive 
calendar years provided that the measurement can be taken during a 
scheduled shutdown and, if there is no scheduled shutdown within three 
consecutive calendar years, the measurement must be made at the next 
scheduled depressurized compressor shutdown. We have included 
additional clarification in this final rule that a scheduled shutdown 
means a shutdown that requires a compressor to be taken off-line for 
planned or scheduled maintenance. A scheduled shutdown does not include 
instances when a compressor is taken offline due to a decrease in 
demand but must remain available. We are not finalizing the proposed 
requirement to perform a measure for each operating mode once every 
three years.
    We are also finalizing provisions, as proposed, that clarify that 
for reporters that elect to conduct ``as found'' measurements for 
individual compressor sources, all measurements from a single owner or 
operator may be used when developing an emission factor (using Equation 
W-24 or W-28 of 40 CFR 98.233) for each compressor mode-source 
combination. If the reporter elects to use this option, the reporter 
emission factor must be applied to all reporting facilities for the 
owner or operator. Finally, we are restructuring and revising the 
centrifugal and reciprocating compressor sections (40 CFR 98.233(o) and 
40 CFR 98.233(p)), as proposed, in order to improve clarity for 
reporters.
b. Summary of Comments and Responses
    This section summarizes the major comments and responses related to 
centrifugal and reciprocating compressors. See the 2014 response to 
comment document in Docket Id. No. EPA-HQ-OAR-2011-0512 for a complete 
listing of all comments and responses.
    Comment: Several commenters stated that the proposed rule did not 
address reporter concerns about measuring emissions from compressors. 
Several commenters requested that the EPA consider developing industry-
wide emission factors to replace the current measurement-based approach 
in subpart W. One commenter requested that the EPA use data from 
outside studies and leverage the data collected from 2011 and 2012 to 
develop emissions factors and remove the annual measurement requirement 
after a reasonable timeframe. Another commenter requested that the EPA 
use emission factors that reflect the recently enacted New Source 
Performance Standards (NSPS) for the natural gas industry (40 CFR part 
60, subpart OOOO). Two commenters suggested that reporter emission 
factors developed for individual compressors should be used when 
compressor sources are comingled with other non-compressor emission 
sources.
    Response: The EPA appreciates the suggestions provided by the 
commenters and agrees that credible and accurate emission factors can 
provide a cost-effective means of calculating GHG emissions for 
purposes of reporting under Part 98. In particular, the EPA is willing 
to consider an emission factor approach under Part 98 for compressors.
    As part of the development of the subpart W 2010 final rule, the 
EPA had previously considered using an emission factor approach for 
compressors. The EPA found that although a 1996 Gas Research Institute 
study on methane emissions from the natural gas industry provides much 
of the current knowledge on which emission factors from this sector are 
based, information on compressors was not necessarily reflective of 
current operational conditions for purposes of GHG reporting and 
therefore additional measurement data were needed in order to 
understand emissions related to specific modes of operation for 
compressors.
    The EPA agrees that facilities have collected data under part 98 
related to centrifugal and reciprocating compressors that can be used 
to inform an emission factor. However, the data which are inputs to 
emissions equations have not yet been reported to the EPA because they 
are deferred for reporting until 2015. The deferred reporting elements 
include the reporter-specific emission factors that are used to 
calculate emissions and the total time that a compressor is in a 
particular mode. The reporter-specific emission factors provide 
information on how measured data are applied to a reporter's other 
compressors that were not measured in a particular mode, and these 
factors are applied to all compressors for the total time each 
compressor is operated in each mode. Therefore the deferred data 
provide important information that could help inform the development of 
emission factors for each mode of operation. The EPA intends to analyze 
this deferred information after it is received in 2015. The EPA notes 
that the prevalence of BAMM in the reported data can affect cross-
facility comparisons for developing emission factors, but the effect of 
BAMM cannot be fully analyzed until the inputs data are reported.
    In addition, the data that will be reported under these final rule 
amendments will provide additional data that can inform the development 
of emission factors, such as information on the power output of the 
compressor driver. Furthermore, the compressor revisions that are being 
finalized in this rule will improve the quality of the reported data 
and address technical issues received from stakeholders during program 
implementation. The EPA also plans to review information that will be 
made available in the near future through outside studies.
    The EPA is committed to working with stakeholders to review 
regulatory requirements, methods, and the quality of the information 
reported. The EPA looks forward to reviewing the deferred Part 98 data, 
data that will be reported under these revisions and data from

[[Page 70364]]

outside studies in order to determine if appropriate emission factors 
can be developed, and, if so, the EPA may revise the calculation and 
reporting requirements for compressors in a future rulemaking.
    Comment: Several commenters objected to the requirements for 
measuring emissions from manifolded compressor sources. Two commenters 
asserted that the proposed rule fails to address issues that may 
preclude measurement from manifolded compressor sources (e.g., unsafe 
to access and technically infeasible measurement locations, or vent gas 
from manifolded compressor sources that is comingled with gas from 
other emission sources) and two commenters noted that compressor vents 
are sometimes manifolded such that obtaining measurements of individual 
compressors is not possible; one of these commenters requested that 
these manifolded compressors be exempt from emissions measurements.
    One commenter stated that the EPA has not addressed the burden 
associated with installing sampling ports on manifolded configurations. 
Another commenter objected to the proposed rule requirements specifying 
that manifolded compressor source emissions must be measured at a 
single point in the manifold downstream of all compressor inputs and 
where emissions cannot be comingled with other non-compressor emission 
sources; this commenter asserted that for compressor sources with 
emissions comingled with other sources, a sample port would need to be 
installed prior to the comingling of gases from the compressor sources 
and the non-compressor sources and could require the shutdown of all 
associated equipment.
    Multiple commenters opposed the proposed requirements to conduct 
three measurements per year for manifolded compressors. One commenter 
claimed that the requirement to collect three measurements appears to 
be arbitrary and is not supported by 2011 or 2012 reported data. The 
commenter contended that the EPA has failed to explain how manifolded 
source-mode emissions data are expected to be different from other 
compressor source emissions data or why three measurements are expected 
to reduce measurement uncertainty associated with dissimilar 
measurements. Three commenters stated that the EPA did not address the 
cost and potential logistical problems associated with the mobilization 
of a test team two additional times per year (i.e., total of three 
times a year) to conduct measurements on manifolded compressor sources. 
One commenter argued that the proposed requirements do not address 
concerns regarding the burden and costs associated with the 
installation of sample ports, or shutdown complications for port 
installation. One commenter argued that the EPA misrepresented the rule 
revision as a positive change beneficial to industry and a reduction in 
burden.
    Response: The EPA disagrees with commenters who object to the need 
to independently categorize compressor source measurements from 
manifolded compressors; however, we acknowledge that some of the 
proposed clarifications inadvertently increased the stringency of the 
rule. The subpart W 2010 final rule included provisions that required 
the measurement of emissions from all vents, including emissions from 
individual compressors manifolded to common vents. The proposed rule 
changes do not alter that requirement and were intended to help current 
reporters to comply with subpart W.
    The existing 2010 measurement requirements apply to the vent from 
the manifolded system without mention of co-mingled emission sources. 
We prefer and encourage measurements of manifolded compressors to be 
performed prior to co-mingling with other sources, as proposed. 
However, based on comments, we recognize that this may not be possible 
for certain installations. Therefore, we are not finalizing this 
provision as proposed. Instead, we are revising the requirement from 
the proposed rule so that the final rule reads as follows ``Measure at 
a single point in the manifold downstream of all compressor inputs and, 
if practical, prior to comingling with other non-compressor emission 
sources''. We are also adding a reporting element for compressor 
measurements of manifolded systems to indicate whether the measurement 
location is prior to comingling with other non-compressor emission 
sources.
    We proposed that reporters that had manifolded compressors be 
required to take at least three measurements per year and report the 
average of the measurements. In this final rule, we are requiring 
reporters to take a single measurement per year from manifolded 
compressors, which is commensurate with the measurement frequency for 
compressors that are not part of a manifolded group of compressors and 
consistent with the existing 2010 measurement requirements.
    Comment: Three commenters requested that the EPA improve the 
definition of ``compressor source'' in 40 CFR 98.238 for clarity. One 
commenter contended that the proposed definition is not sufficiently 
clear to manage compliance and could lead to broad interpretation to 
sources not specifically called out in the rule. The commenter 
requested that the definition for ``compressor source'' be revised to 
specifically list the required sources.
    Response: The EPA agrees with commenters that the proposed 
definition for ``compressor source'' could be read as potentially 
ambiguous and create confusion with regards to compliance with Part 98. 
Therefore, we are clarifying the definition of ``compressor source'' in 
this final rule to specify the applicability of the rule to specific 
compressor emission sources. We are finalizing the definition for 
``compressor source'' to mean ``the source of certain venting or 
leaking emissions from a centrifugal or reciprocating compressor. For 
centrifugal compressors, ``source'' refers to blowdown valve leakage 
through the blowdown vent, unit isolation valve leakage through an open 
blowdown vent without blind flanges, and wet seal oil degassing vents. 
For reciprocating compressors, ``source'' refers to blowdown valve 
leakage through the blowdown vent, unit isolation valve leakage through 
an open blowdown vent without blind flanges, and rod packing 
emissions.'' These revisions clearly delineate the emission sources for 
which reporters must measure and account for emissions in the final 
rule.
    Comment: Several commenters opposed the proposed requirements to 
measure compressors in the NOD mode once every 3 years, provided that a 
measurement can be taken during a scheduled shutdown. Three commenters 
requested that the EPA eliminate the requirement to measure compressors 
in the NOD mode in its entirety. One commenter argued that the proposed 
rule fails to provide sufficient justification to continue to require 
NOD mode measurements every three years. Another commenter argued that 
based on the monitoring data collected to date, the NOD mode compressor 
emissions are minimal, and the monitoring requirements are not cost 
effective. Another commenter stated that the measurements collected in 
2011 and 2012 show that transmission and storage sources completed 
hundreds of measurements in the NOD mode, with about the same number of 
``as found'' tests completed in shutdown mode as other modes.
    Response: The EPA disagrees with commenters opposed to the proposed 
requirements to measure compressors in the NOD mode. The EPA 
established the requirements to measure compressors in the NOD mode 
once every 3 years as

[[Page 70365]]

part of the subpart W 2010 final rule. As the EPA previously noted (75 
FR 18608, April 12, 2010), depending on operational practices, the 
various operating modes of centrifugal and reciprocating compressors 
may have significantly different emissions. The EPA noted at that time 
that unit isolation valves and compressor blowdown valves can have 
excessive leakage, especially when a compressor is not in operation. 
Following consideration of commenter input, the EPA finalized as part 
of the subpart W 2010 final rule these provisions to require 
measurements in the NOD mode once every 3 years.
    The EPA reviewed the 2011, 2012 and 2013 reported emissions data 
for compressors and determined that compressor emissions from the NOD 
mode can contribute to a significant amount of the measured emissions 
for centrifugal compressors and reciprocating compressors. For more 
information, see the memorandum, ``Greenhouse Gas Reporting Rule: 
Technical Support for 2014 Revisions and Confidentiality Determinations 
for Petroleum and Natural Gas Systems; Final Rule'' in Docket Id. No. 
EPA-HQ-OAR-2011-0512. Therefore, we are not removing the requirement to 
measure emissions from compressors in the NOD mode in this final rule.
    Comment: Several commenters stated that the EPA has not considered 
logistical issues in developing the requirements to measure compressors 
in the NOD mode once every 3 years, provided that a measurement can be 
taken during a scheduled shutdown. One commenter claimed that the 
proposed ``scheduled shutdown'' exception to the three-year requirement 
does not avoid the costs associated with mandatory testing in the NOD 
mode, such as out-of-sequence scheduling costs or the obligation to 
maintain records on compressor shutdown testing status. Two commenters 
stated that operators would likely force unit shutdowns while the 
measurement contractor is on site, which could result in the emissions 
of additional GHGs.
    One commenter supported the proposed revision to allow the 
measurement to be taken during the next scheduled depressurized 
shutdown, however, the commenter asked that the scheduled shutdown not 
include instances when a scheduled compressor shutdown is only for a 
short duration, such that it is not possible to complete the 
measurement, or when a ``scheduled shutdown'' may occur without 
sufficient lead time to arrange for or mobilize a measurement team. 
Four commenters stressed that the proposed rule did not clearly define 
what constitutes a shutdown or ``scheduled shutdown.'' Another 
commenter noted that transmission compressors often start up and 
``shutdown'' to meet demands; the commenter stated that it is not clear 
if this type of ``shutdown'' would be included under the proposed rule 
text. One commenter requested that the EPA provide a definition for the 
term ``scheduled shutdown'' that includes a shutdown of longer duration 
and likely associated with major maintenance and unit unavailability. 
Another commenter requested that the definition refer to a major 
maintenance outage that is scheduled months in advance, as opposed to a 
shutdown scheduled in direct response to a particular event (e.g., in 
response to change in demand or operational disruption). One commenter 
argued that even if a scheduled shutdown refers to extended compressor 
shutdown for major maintenance, facilities would still face scheduling 
and logistical issues as well as increased costs.
    One commenter responded to the EPA's request for comment on the 
option of requiring measurements in the NOD mode every five years 
rather than every three years. The commenter requested that the EPA 
extend the monitoring frequency to once every five years but noted that 
this change may not result in a unit being available at a specific 
time. The commenter suggested that emission factors be developed for 
the NOD mode as soon as feasible.
    Response: The EPA is aware of commenter concerns regarding the need 
to shut down, purge, and blow down emissions from compressors in order 
to conduct emissions measurements. We are reducing the burden on 
facilities by augmenting the three-year measurement requirement to 
specify that reporters must take a measurement in the NOD mode within 
three years or at the next scheduled shutdown. If three consecutive 
calendar years occur without measuring the compressor in the NOD mode, 
then we are requiring that the NOD mode measurement must be made at the 
next scheduled depressurized compressor shutdown. We agree with 
commenters that indicated that the term ``scheduled shutdown'' was 
potentially nebulous and requires clarification. Therefore, we are 
clarifying in this final rule that a scheduled shutdown means a 
shutdown that requires a compressor to be taken off-line for planned or 
scheduled maintenance. This may include maintenance such as replacement 
of compressor rod packing for reciprocating compressors or replacement 
of wet or dry seals in centrifugal compressors. A scheduled shutdown 
does not include instances when a compressor is taken offline due to a 
decrease in demand but remains available to meet increases in demand. 
These final revisions clarify that operators do not have to plan a 
shutdown of their equipment solely to take a measurement of their 
compressor in the NOD mode but may take the measurement as part of 
regular planned maintenance. These revisions also clarify that the 
compressor must be depressurized. These provisions will ensure that 
facilities have sufficient time to mobilize a test team and coordinate 
testing to occur during periods of planned shutdown. Therefore, this 
will reduce the need for reporters to schedule additional shutdowns 
outside of planned maintenance, reducing compliance costs. Although the 
EPA considered extending the period to collect measurements in the NOD 
mode to every 5 years, it would not necessarily alleviate reporter 
concerns regarding the need to schedule a shutdown solely for emissions 
measurements. As the EPA has previously noted in finalizing the subpart 
W 2010 final rule, three years is generally accepted as the period 
during which compressors would be shut down for regular maintenance. 
Therefore, we have determined that the final provisions provide an 
adequate extension for reporters for which the maintenance period 
extends beyond 3 years, while ensuring that the EPA collects the data 
in a timely manner as it comes available.
    Comment: Two commenters objected to the proposed requirement to 
complete operating-mode measurements every three years or the next year 
that compressor operation exceeds 2,000 hours. These commenters stated 
that the EPA has not justified the need for or explained the benefit of 
this requirement in the proposed rule or the technical support 
document. Both commenters remarked that the subpart W measurement data 
currently reported includes hundreds of operating-mode tests completed 
within the first two years. One commenter stated that, at a minimum, 
the EPA should review and analyze 2011-2013 data to ascertain the need 
for such requirements. One commenter asserted that the proposed time 
interval has no basis. Two commenters stated that the proposed 
requirement would unnecessarily increase compliance costs in excess of 
EPA's presumed costs for completing measurements.
    Multiple commenters requested that compressor measurements be 
completed

[[Page 70366]]

``as found'' without mandating mode-specific measurements. Three 
commenters noted that because the annual as-found measurements have 
already generated data in all three modes, further mode- and time-
specific testing does not result in additional meaningful emissions 
data. The commenters urged that the proposed rule failed to justify the 
need for further mode- and time-specific testing requirements.
    Response: The EPA proposed this change in order to ensure data for 
all compressor operating modes would be collected for all compressors. 
After considering comments and further reviewing the available reported 
data, the EPA concluded that additional mode specific measurements to 
ensure characterization of modes other than not-operating-depressurized 
mode are not necessary. Therefore, we are not finalizing the proposed 
requirement to perform a measure for each operating mode once every 
three years.
    Comment: Five commenters objected to revisions in the proposed rule 
that appeared to eliminate the use of the acoustic method for blowdown 
valve leakage measurements for centrifugal compressors in operating-
mode and for reciprocating compressors in operating mode or standby-
pressurized-mode. The commenters noted that EPA had added a provision 
for leak rate quantification to the existing subpart W rule in response 
to comments on the re-proposed subpart W rule, in order to address 
concerns regarding safety or inaccessibility issues for some vent 
measurements. Commenters stated that the EPA had previously included 
this method to ensure safety in the collection of data from certain 
sources. One commenter noted that in the first three reporting years, 
many reporters have relied on the acoustic method for reciprocating 
compressor and centrifugal compressor measurements of isolation valve 
and blowdown valve leakage and condensate tank dump valve leakage. 
Several commenters requested that this method not be eliminated unless 
other alternative rule requirements, such as the use of an infrared 
camera for screening, are implemented.
    Three commenters recommended that the EPA consider allowing the use 
of an infrared (IR) camera for screening vents that require 
measurement. These commenters requested that the rule include 
additional viable measurement methods and contended that an IR camera 
option would provide flexibility for reporters. One commenter noted 
that the IR camera could be used to screen for leaks from compressor 
isolation valves, blowdown valves, or rod packing released through a 
vent and identify whether vent measurement is needed. The commenter 
asserted that this method would be invaluable for screening vents that 
are unsafe or impractical to access. The commenter stated that several 
companies have received approval of BAMM requests to use the IR camera 
to screen these compressor sources for emissions.
    Response: The EPA agrees with commenters that the acoustic device 
measurement method should not be eliminated from the final rule. During 
the revision of the centrifugal and reciprocating compressor 
calculation and monitoring requirements, the use of the acoustic device 
measurement for blowdown valve leakage for centrifugal and 
reciprocating compressors was erroneously removed. The EPA has 
previously allowed the use of acoustic device measurement to address 
concerns regarding safety or inaccessibility issues for some vent 
measurements, and we are aware that many reporters have relied upon 
acoustic device measurement to comply with the rule. The EPA 
understands the safety and inaccessibility concerns raised by 
commenters, and we did not intend to remove these provisions or to 
reduce flexibility for reporters in the proposed rule. In this final 
rule, we are maintaining provisions that allow for quantification of 
emissions due to leaks from compressor blowdown valve leakage using an 
acoustic leak detection device. Specifically, we have included these 
provisions in 40 CFR 98.233(o)(2)(i)(C) and 40 CFR 98.233(p)(2)(i)(C) 
of the final rule.
    The EPA also agrees with the commenters' suggestion to allow for 
the use of optical gas imaging equipment or an infrared (IR) camera for 
compressor vent screening. The EPA has reviewed the methods in 40 CFR 
98.234(a) and determined that these methods are appropriate for pre-
screening for leakage from compressor vents. The use of an IR camera is 
currently allowed under subpart W to screen for dump valve leakage 
through tank vents in 40 CFR 98.233(k) and is a proven tool for 
identifying leakage from these emissions sources. Therefore, we have 
determined that it would be appropriate to allow the use of the methods 
in 40 CFR 98.234(a) for pre-screening of emissions from isolation 
valves, blowdown valves, or rod packing released through a vent, 
provided that sources conduct follow-up measurements if leaks are 
detected. The EPA agrees with commenters that this method would provide 
flexibility for reporters. We are finalizing provisions in 40 CFR 
98.233(o)(2)(i)(D) and 40 CFR 98.233(p)(2)(i)(D) to allow the use of 
the methods in 40 CFR 98.234(a) to allow for pre-screening for leaks 
from compressor isolation valves, blowdown valves, or rod packing 
released through a vent. Reporters may use this method to identify 
whether further vent measurement is needed. If any emissions are 
detected, then reporters are required to use one of the methods 
currently specified in subpart W (acoustic leak detection device, 
calibrated bagging or high volume sampler, or temporary meter such as a 
vane anemometer) to quantify emissions. If no emissions are detected, 
the reporter would not be required to follow-up with a measurement to 
quantify emissions. We do not anticipate that these final revisions 
will negatively impact the quality of the data collected, as reporters 
will continue to use the existing measurement methods under subpart W 
to quantify emissions that are detected using the IR camera.
12. Natural Gas Distribution: Leak Detection Equipment and Emissions 
From Components
a. Summary of Final Revisions
    The EPA is finalizing, with minor revisions from the proposed rule, 
amendments to revise Equations W-30A, W-30B, W-31, W-32A and W-32B to 
place the natural gas distribution facility meter/regulator run 
emission factors calculation in 40 CFR 98.233(q) instead of 40 CFR 
98.233(r) while also clarifying that the emission factor is calculated 
separately for CO<INF>2</INF> and CH<INF>4</INF> and is on a meter/
regulator run operational hour basis instead of a meter/regulator run 
component basis. The proposed rule inadvertently omitted appropriate 
provisions for calculating and reporting emissions from equipment leaks 
at above-grade transmission-distribution stations that are not surveyed 
during the reporting year as noted in the public comments received. 
Therefore, the EPA is finalizing minor revisions to Equations W-31 and 
W-32B as well as 40 CFR 98.233(q) introductory text, (q)(8)(ii) and 
(iii), and adding paragraph (q)(9) to specify how emissions from 
equipment leaks at above-grade transmission stations not surveyed 
during the reporting year are to be calculated. In the final rule, 
facilities must calculate annual emissions from above-grade 
transmission-distribution transfer stations surveyed during the 
calendar year using Equation W-30 of 40 CFR 98.233(q). The emissions 
are calculated in Equation W-30 on a per-component basis based on 
equipment leak survey results and emission factors for above-

[[Page 70367]]

grade transmission-distribution transfer station components listed in 
Table W-7. The results of the component-level annual emissions 
calculations using Equation W-30 are then used to develop the annual 
facility meter/regulator run population emission factors for 
CO<INF>2</INF> and CH<INF>4</INF> using Equation W-31. Paragraph 40 CFR 
98.233(q)(8)(iii) was revised from proposal to provide more specificity 
on how the emission factors from Equation W-31 must be recalculated as 
additional equipment leak survey data become available from above-grade 
transmission-distribution transfer stations that use a multiple year 
equipment leak survey cycle. To calculate annual emissions from above-
grade metering-regulating stations that are not above-grade 
transmission-distribution transfer stations and from all above-grade 
transmission-distribution transfer stations at facilities that use a 
multiple year equipment leak survey cycle must use the emission factors 
(calculated in Equation W-31) in the annual emissions calculation of 
Equation W-32B in 40 CFR 98.233(r). The primary difference from 
proposal is that the calculations for above-grade transmission-
distribution transfer stations that elect to use a multiple year 
equipment leak survey cycle, which were inadvertently omitted, are now 
specified in the new paragraph at 40 CFR 98.233(q)(9). Completing the 
calculations for all above-grade transmission-distribution transfer 
stations allows for more unified reporting of the emissions for all 
above-grade transmission-distribution transfer stations 40 CFR 
98.236(q).
    As proposed, emissions from below-grade metering-regulating 
stations, below-grade transmission-distribution transfer stations, 
distribution mains, and distribution services are calculated using 
Equation W-32A of 40 CFR 98.233(r) using population emission factors 
listed in Table W-7.
    The EPA is also finalizing the definition of ``meter/regulator 
run'' with minor revisions from the proposed rule. The revisions 
clarify that the term ``meter/regulator run'' refers only to components 
in the natural gas distribution industry segment. The final definition 
of ``meter/regulator run'' reads as follows: ``Meter/regulator run 
means a series of components used in regulating pressure or metering 
natural gas flow, or both, in the natural gas distribution industry 
segment. At least one meter, at least one regulator, or any combination 
of both on a single run of piping is considered one meter/regulator 
run.''
b. Summary of Comments and Responses
    This section summarizes the major comments and responses related to 
leak detection equipment and emissions from components for the natural 
gas distribution segment. See the 2014 response to comment document in 
Docket Id. No. EPA-HQ-OAR-2011-0512 for a complete listing of all 
comments and responses.
    Comment: One commenter noted that proposed text for 40 CFR 
98.233(q)(8)(i) allows all distribution facility above-grade 
transmission-distribution transfer stations to be surveyed over 
multiple years up to a five-year cycle, while the emission calculation 
requirements of 40 CFR 98.233(q) and emission reporting requirements of 
40 CFR 98.236(q)(2) only apply to equipment leaks at above-grade 
transmission-distribution stations surveyed during the reporting year. 
The commenter noted that emissions for equipment leaks at the above-
grade transmission-distribution transfer stations not surveyed during 
the reporting year are not calculated or reported. The commenter 
suggested revising the associated text and equations to calculate these 
emissions using Equation W-32B and the emission factors calculated 
using Equation W-31.
    Response: The commenter is correct that the proposed revisions 
inadvertently omitted provisions for calculating and reporting 
emissions from above-grade transmission-distribution transfer stations 
that were not surveyed in the first cycle of a multi-year cycle. In 
this final rule, natural gas distribution facilities may choose to 
conduct equipment leak surveys at all above-grade transmission-
distribution transfer stations over multiple years, not exceeding a 
five year period. To account for annual emissions from above-grade 
transmission-distribution transfer stations that have not been surveyed 
in the current survey cycle (i.e., whose emissions were not calculated 
using Equation W-30), we are revising the language proposed in 40 CFR 
98.233(q)(8) and adding a paragraph (q)(9) to clarify that facilities 
must use the emission factors (calculated in Equation W-31) in the 
annual emissions calculation of Equation W-32B in 40 CFR 98.233(r). 
Additionally, we are revising the term ``Count<INF>M,R</INF>'' in 
Equation W-32B to include meter/regulator runs at above-grade 
transmission-distribution transfer stations when required to be used 
according to the new paragraph at 40 CFR 98.233(q)(9). We are 
finalizing harmonizing edits to 40 CFR 98.236(q) and removing some 
reporting elements in 40 CFR 98.236(r) to clarify the applicability of 
the reporting requirements for equipment leaks at the above-grade 
transmission-distribution transfer stations and adding specific 
requirements for reporting elements when equipment leak surveys for 
above-grade transmission-distribution transfer stations are performed 
using multiple year cycles.
13. Calculation of GHG Emissions From Natural Gas Volume Emissions
a. Summary of Final Revisions
    We are finalizing revisions as proposed to clarify onshore natural 
gas transmission compression, LNG storage, LNG import and export, and 
natural gas distribution facilities may use either site-specific 
composition or a default gas composition (95 percent CH<INF>4</INF> and 
1 percent CO<INF>2</INF>) to calculate GHG emissions from natural gas 
volume emissions at 40 CFR 98.233(u)(2)(iii), (v), (vi) and (vii). We 
are also finalizing analogous revisions to 40 CFR 98.233(u)(2)(iv) to 
clarify the option to use either site-specific composition data or a 
default gas composition (95 percent CH<INF>4</INF> and 1 percent 
CO<INF>2</INF>) for underground natural gas storage facilities as well. 
The EPA requested comment on whether the use of site-specific 
composition data for calculating emissions should be required or 
optional. The EPA received comments supporting only the optional use of 
site-specific gas composition data; no commenters supported the 
mandatory use of site-specific gas composition data.
    We are also finalizing several clarifications regarding the need to 
calculate emissions for certain equations in actual conditions based on 
public comments received. The EPA intended that the existing provision 
in 40 CFR 98.233(t) allowed for measurements to be made at standard 
conditions even when the equations specified actual conditions. 
However, we concluded that additional revisions could clarify this 
intent for reporters. First, we are finalizing revisions to the 
introductory text at 40 CFR 98.233 to read: ``You must calculate and 
report the annual GHG emissions as prescribed in this section. For 
calculations that specify measurements in actual conditions, reporters 
may use a flow or volume measurement system that corrects to standard 
conditions and determine the flow or volume at standard conditions; 
otherwise, reporters must use average atmospheric conditions or typical 
operating conditions as applicable to the respective monitoring methods 
in this section.'' Second, the introductory text at 40 CFR 98.236 is 
revised to read: ``In

[[Page 70368]]

addition to the information required by Sec.  98.3(c), each annual 
report must contain reported emissions and related information as 
specified in this section. Reporters that use a flow or volume 
measurement system that corrects to standard conditions as provided in 
the introductory text in Sec.  98.233 for data elements that are 
otherwise required to be determined at actual conditions, report gas 
volumes at standard conditions rather the gas volumes at actual 
conditions and report the standard temperature and pressure used by the 
measurement system rather than the actual temperature and pressure.''
b. Summary of Comments and Responses
    Comment: Several commenters stated that requiring the conversion of 
gas flow rates from ``standard conditions'' to ``actual conditions'' 
when applying required estimation methodology is burdensome and overly 
complicated. These estimations then have to be converted back into 
standard conditions for reporting under the regulatory requirements. 
Since instrumentation used in the industry typically measures gas flow 
rates in standard conditions, the commenters requested the EPA to 
revise Equations W-3, W-4A, W-4B, W-7, W-17A, W-17B, W-34, W-39A, and 
W-39B to reflect that the measured gas volumes and/or estimated gas 
volumes used in these equations, and the resulting emissions, are in 
standard conditions to better meet reporting requirements and 
consistency.
    Response: The EPA reviewed the existing provision in 40 CFR 
98.233(t), which states that ``[i]f equation parameters in Sec.  98.233 
are already at standard conditions, which results in volumetric 
emissions at standard conditions, then paragraph (t) does not apply,'' 
and concluded that it effectively allows for measurement in either 
standard or actual conditions. However, in reviewing the calculation 
requirements in 40 CFR 98.233 and the reporting requirements in 40 CFR 
98.236, we understand that additional clarity could be provided. We 
recognize that there are automated flow or volume measurement systems 
that automatically convert measurements to standard conditions. It was 
not our intent to require facilities to convert these data to actual 
conditions to fulfill the certain calculation and reporting 
requirements, then convert the volumes back to standard conditions 
prior to determining GHG mass emissions. We disagree with the 
commenters' suggestion that all of these equations should be expressed 
in standard conditions because not all facilities automatically correct 
the actual volumetric flow measured to standard conditions. Our intent 
was to provide an allowance to use either actual volumetric flow at the 
conditions present or volumetric flow corrected to standard conditions. 
In order to clarify this intent for reporters, we are finalizing 
revisions to the introductory text at 40 CFR 98.233 and 98.236 to 
clarify that use of systems that automatically correct to standard 
conditions is allowed. Specifically, the introductory text at 40 CFR 
98.233 is revised to read, ``You must calculate and report the annual 
GHG emissions as prescribed in this section. For calculations that 
specify measurements in actual conditions, reporters may use a flow or 
volume measurement system that corrects to standard conditions and 
determine the flow or volume at standard conditions; otherwise, 
reporters must use average atmospheric conditions or typical operating 
conditions as applicable to the respective monitoring methods in this 
section.'' The introductory text at 40 CFR 98.236 is revised to read, 
``In addition to the information required by Sec.  98.3(c), each annual 
report must contain reported emissions and related information as 
specified in this section. Reporters that use a flow or volume 
measurement system that corrects to standard conditions as provided in 
the introductory text in Sec.  98.233 for data elements that are 
otherwise required to be determined at actual conditions, report gas 
volumes at standard conditions rather the gas volumes at actual 
conditions and report the standard temperature and pressure used by the 
measurement system rather than the actual temperature and pressure.''
    Comment: Five commenters supported the option to use site-specific 
data while retaining the option to use the default methane and 
CO<INF>2</INF> composition values currently specified in subpart W. 
Four of these commenters stated that the use of site-specific 
composition data should not be mandatory. One commenter noted that 
compressor stations are normally not equipped with gas chromatographs 
for determination of site-specific gas composition; the commenter 
stated that mandatory reporting of site-specific gas composition would 
require the collection of extended gas analyses annually at each 
compressor station. Two commenters remarked that requiring mandatory 
use of site-specific composition data would result in increased costs 
and burden to reporters. Other commenters stated that the optional use 
of site-specific composition data adds flexibility for operators 
already using site gas quality data for other reporting purposes. Two 
commenters remarked that retaining the use of default composition 
values simplifies reporting without compromising GHG emission estimates 
for operators. These commenters noted that natural gas composition 
values downstream of natural gas processing facilities are much less 
variable than upstream operations.
    Response: Paragraphs at 40 CFR 98.233(u)(2)(iii) through (vii) 
previously specified that these facilities ``may'' use the default 
composition, but they did not clearly specify the alternative to the 
default. In the proposed rule, we clarified that the alternative to the 
default was ``site specific engineering estimates based on best 
available data.'' The EPA specifically requested comment on whether the 
use of site-specific composition data for calculating emissions should 
be required or optional and solicited information on when a facility 
would not have site-specific composition data available. As the 
commenters noted, determining site-specific composition data based on 
measurement data would add burden to the industry, particularly where 
appropriate sampling and analysis equipment are not available. However, 
we note that the proposed language did not limit the site-specific 
composition to be based on site-specific measurement data, but rather 
``site specific engineering estimates based on best available data.'' 
We agree with commenters that facilities should be allowed to use site-
specific data when the data are available. We also agree with 
commenters that, when data are not available, the default values are 
reasonable alternatives for industries downstream of the processing 
plants. Therefore, after considering the information provided by 
commenters, the EPA is finalizing revisions in 40 CFR 98.233(u)(2)(iii) 
through (vii) to clarify that natural gas transmission compression, 
underground natural gas storage, LNG storage, LNG import and export, 
and natural gas distribution facilities may use either site-specific 
composition data (based on engineering estimates) or the default gas 
compositions.
14. Onshore Petroleum and Natural Gas Production and Natural Gas 
Distribution Combustion Emissions
1. Summary of Final Revisions
    In this final rule, the EPA is clarifying that emissions and volume 
of fuel combusted must be reported for all internal combustion units 
that drive

[[Page 70369]]

compressors in 40 CFR 98.236. The EPA is revising this reporting 
requirement to be consistent with the emission estimation methods in 40 
CFR 98.233(z)(4), which specify that the exemption from reporting 
emissions for internal combustion units with a rated heat input 
capacity less than or equal to 1 mmBtu per hour (130 hp) does not apply 
to internal fuel combustion sources that drive compressors. These 
revisions are finalized as proposed. We are also finalizing revisions 
to the description of the ``HHV'' term for Equation W-40 with minor 
revisions from the proposed rule. Specifically, we are finalizing that, 
for field gas or process vent gas, the reporter may use either the 
default higher heating value (HHV) or a site-specific HHV.
2. Summary of Comments and Responses
    Comment: One commenter requested that the EPA modify the 
description of the term ``HHV'' used in Equation W-40 to allow the use 
of site-specific (measured) higher heating values for field gas or 
process vent gas, when the data are available, as an alternative to the 
currently specified default value. The commenter noted that allowing 
the use of site-specific HHV data would be similar to the proposed 
changes to allow site-specific GHG concentrations instead of default 
values.
    Response: We agree with the commenter that the use of measured 
higher heating values should be allowed, when available. It was not our 
intent to mandate the use of the HHV default value but to allow its use 
when measurement data were not available. Therefore, we are finalizing 
the description of the ``HHV'' term in Equation W-40 to read as 
follows: ``Higher heating value of fuel, mmBtu/unit of fuel (in units 
consistent with the fuel quantity combusted). For field gas or process 
vent gas, you may use either a default higher heating value of 1.235 x 
10<SUP>-3</SUP> mmBtu/scf or a site-specific higher heating value.''

C. Summary of Final Revisions to Missing Data Provisions

1. Summary of Final Revisions
    The EPA is finalizing amendments to 40 CFR 98.235, with revisions 
from the proposed rule, to clarify the procedures for addressing 
missing data. We proposed various missing data procedures for different 
types or frequencies of measurement data. For AGR vents, we proposed 
that missing quarterly samples must use the average of the value of the 
last four quarterly samples. We received comments on how to implement 
this requirement when less than four quarters of data are available 
(e.g., for new sources). Rather than establishing unique missing data 
procedures for this source, we are finalizing a requirement for these 
sources to use the ``before'' and ``after'' approach analogous to the 
missing data procedures proposed for continuous measurement data. 
Similarly, we are also finalizing, with minor revisions from proposal, 
the missing data requirements for measurement devices such as 
continuous flow monitors and composition analyzers to standardize these 
requirements to all measurements required by the rule except for annual 
measurement data. For stationary and portable combustion sources, we 
are finalizing amendments as proposed to require reporters to use the 
missing data procedures in subpart C of part 98.
    As proposed, the EPA is finalizing amendments to allow the use of 
best engineering estimates for any parameter that cannot be reasonably 
measured or obtained according to the requirements in subpart W for up 
to 6 months from the facility's first date of subpart W applicability. 
We are also finalizing, with minor revisions from proposal, amendments 
to allow the use of best engineering estimates for any parameter that 
cannot be reasonably measured or obtained according to the requirements 
in subpart W for up to 6 months for facilities that are subject to 
subpart W and that acquire new sources from another facility that is 
not subject to reporting under subpart W. We originally proposed this 
amendment for new wells, but after reviewing the public comments 
received, we determined this allowance should be more broadly applied 
to any new emissions source acquired by the existing facility from 
another facility that is not subject to reporting under subpart W. Only 
data and calculations associated with those newly acquired sources fall 
under these provisions.
    We are finalizing missing data provisions for annual and biannual 
(once every two year) measurements that are similar to the previous 
missing data requirements in 40 CFR 98.235 as provided in the subpart W 
2010 final rule. These provisions require repeat of the estimation or 
measurement as soon as possible, with allowance to use measurements 
made after December 31 (in the subsequent year) as substitute values 
for the missing data in the reporting year.
    We are not finalizing the reporting requirements for use of missing 
data procedures as proposed. In the proposed rule, we required missing 
data elements to be reported with significant specificity, including 
dates in which substitution values were used, equations in which the 
substitute value is used, a description of the circumstances that led 
to missing data, a description of the procedure used to develop the 
substitute value, the missing data procedure citation claimed, and a 
description of how missing data procedures will be avoided in the 
future. After reviewing public comments, we determined that reporting 
for missing data should more closely align with the requirements in 
other Part 98 source categories as guided by the requirements in 40 CFR 
98.3(c)(8). We are finalizing reporting requirements to identify the 
data element for which missing data procedures were used and the number 
of hours (or required measurements) for which missing data procedures 
were used. We are also finalizing recordkeeping requirements regarding 
the use of missing data procedures to include some of the detail of the 
proposed reporting requirements. Specifically, reporters that use 
missing data procedures are required to keep a record listing the 
emission source type, a description of the circumstance that resulted 
in the need to use missing data procedures, the missing data provisions 
in 40 CFR 98.235 that apply, the calculation or analysis used to 
develop the substitute value, and the substitute value.
2. Summary of Comments and Responses
    This section summarizes the major comments and responses related to 
missing data provisions. See the 2014 response to comment document in 
Docket Id. No. EPA-HQ-OAR-2011-0512 for a complete listing of all 
comments and responses.
    Comment: Several commenters recommended that if BAMM is eliminated 
as proposed, then the missing data provisions should be expanded to 
include all case-specific monitoring circumstances for which the EPA 
has previously reviewed and approved BAMM requests from 2011 through 
2014, including (1) vent lines that cannot be safely or feasibly 
measured and where acoustic device measurement is not an option; (2) 
equipment and piping configurations that cannot be easily modified 
without incurring significant expense and operational delays; and (3) 
compressor measurement data in a specific mode.
    Response: The EPA has considered the implications of removing BAMM 
requirements and commenters' concerns. Although the EPA indicated in 
the preamble to the proposed rule

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that missing data procedures may provide clarity for reporters who may 
have unintentionally missed collecting required data, the missing data 
procedures are not intended to replace BAMM or to be used by reporters 
as BAMM. In the final rule, the EPA is finalizing multiple revisions to 
the rule that address commenter concerns related to BAMM. See Section 
II.D of this preamble for further discussion on BAMM.
    Comment: Four commenters suggested that missing data procedures be 
expanded beyond ``activity data'' specified in 40 CFR 98.235(g) to 
include emissions from locations that are required to be directly 
measured and other data such as temperature and pressure. The 
commenters asserted there are situations where standard measurement 
procedures cannot be conducted and alternatives are necessary. These 
commenters asked the EPA to clarify whether activity data include the 
data elements similar to those used in Equation W-6 (e.g., atmospheric 
pressure; pressure of the gas being discharged; percent of packed 
vessel volume that is gas; and the number of dehydrator openings in the 
calendar year). Other commenters asked that the missing data provisions 
specifically account for compressor vent and rod packing measurements. 
These commenters indicated it is not clear whether the EPA intended to 
include these measurements in 40 CFR 98.235(g).
    Response: Activity data referred to in 98.235(g) includes data that 
are not measured, such as counts of the number of dehydrator openings 
in the calendar year. The provisions proposed in 40 CFR 98.233(g) were 
intended to cover only activity data values used in emissions 
calculations that could not be determined using the methods in 40 CFR 
98.233; it does not refer to values that are required to be measured. 
In our proposed revisions of the missing data provisions, the EPA 
inadvertently omitted missing data procedures for measurements 
conducted annually, such as compressor measurements, or biannually, 
such as flow measurements of well venting for liquids unloading and 
flowback determinations for gas well venting during completions and 
workovers with hydraulic fracturing. It was our intent to maintain the 
existing missing data procedures for these data elements, which entails 
re-measurement of the emissions source. The EPA expects all reporters 
to comply with annual measurement requirements as specified in 40 CFR 
98.233, unless the missing data provisions for new facilities or newly 
acquired sources apply. However, the EPA agrees with the commenters 
that missing data procedures are needed for the annual measurements to 
accommodate a variety of issues that may arise during sampling and 
analysis, including sample breakage during shipping, equipment 
malfunction during analysis. Therefore, we have included in this final 
rule specific missing data procedures for all estimation and 
measurements that are required to be performed annually or biannually. 
These provisions are the same as the previous missing data requirements 
in 40 CFR 98.235 as provided in the subpart W 2010 final rule. These 
provisions require repeat of the estimation or measurement as soon as 
possible, with allowance to use measurements made after December 31 (in 
the subsequent year) as substitute values for the missing data in the 
reporting year.
    Comment: One commenter recommended a clarification of the missing 
data provisions for transmission storage tanks in 40 CFR 98.235(b). The 
commenter pointed out that although the provisions indicated that 
leakage for the entire year should be assumed, it does not provide a 
leak rate. The commenter suggested that the provisions allow for the 
use of a default rate equal to the leak rate threshold of 3.1 standard 
cubic feet (scf) per hour defined in 40 CFR 98.234(a)(5).
    Response: The commenter is correct in noting that the measured 
emissions rate is critical to the calculation and that the proposed 
missing data procedures in 40 CFR 98.235(b) could be improved for 
calculating the emissions. The EPA disagrees that the default value of 
3.1 scf per hour referenced by the commenter should be used. The value 
of 3.1 scf per hour in 40 CFR 98.234(a)(5) is the minimum level of a 
leak that can be detected with the acoustic leak detection device. If a 
leak is present, the leak can have a much higher flow rate than this 
value. In this case, assigning a default leak rate may grossly 
underestimate the emissions. As noted previously in this preamble 
section, the EPA has included in this final rule specific missing data 
procedures for all estimation and measurements that are required to be 
performed annually. These provisions require repeat of the estimation 
or measurement as soon as possible, with allowance to use measurements 
made after December 31 (e.g., in the subsequent year) as substitute 
values for the missing data in the reporting year.
    Comment: Some commenters suggested 40 CFR 98.235(e) should be 
revised to allow best engineering estimates for the first reporting 
year for facilities that become newly subject to subpart W. One 
commenter pointed out that a late year event (e.g., unexpected blowdown 
in December) could result in a facility becoming newly subject to the 
rule. Two commenters asserted that 6 months was not sufficient and that 
a facility would require the use of best engineering estimates for the 
initial reporting year because the previously not subject facility 
would not have been collecting all data required for subpart W 
reporting. These commenters argued that these provisions should be 
available to both newly affected facilities and subject facilities with 
new emissions sources. Similarly, other commenters requested that 40 
CFR 98.235(f) be broadened for all subpart W emission sources (rather 
than just wells) for the scenario where there is a change (e.g., new 
source, new acquisition) at a subject facility, and the reporter cannot 
reasonably acquire necessary data. One commenter provided an example of 
adding new compression capacity on-line late in the year at a 
transmission or storage facility to meet demands in the winter months. 
The commenter stressed that it would be difficult and overly burdensome 
to require vent measurements from newly installed compressors. Another 
commenter requested that 40 CFR 28.235(f) be applicable to newly 
acquired wells whether or not the well was subject to subpart W 
previously.
    Response: The EPA contends that 6 months is enough time for a newly 
subject facility to begin using the methods required in 40 CFR 98.233. 
The reporting rule general provisions at 40 CFR 98.2(h) recommend that 
facilities reassess applicability (including revising any relevant 
emissions calculations) whenever there is any change that could cause a 
facility to meet the applicability requirements of Part 98. Therefore, 
facilities which currently operate just under the reporting threshold 
for subpart W are aware of what changes would likely cause the facility 
to become subject to subpart W and should have an understanding of the 
calculation reporting requirements; although reporters may not be aware 
when an unexpected blowdown will occur, they would know whether an 
unexpected blowdown could cause them to be subject. The reporting rule 
general provisions at 40 CFR 98.3(b)(3) also state that if a facility 
becomes subject, the first annual report must cover the month during 
which the change that caused them to exceed the applicability limit 
occurred and the remainder of the year. Therefore, the facility does 
not

[[Page 70371]]

have to report measurements on the preceding months when no 
measurements were conducted. We have clarified 40 CFR 98.235(f) to 
specify that these missing data procedures apply to source types that 
were acquired from another company and were not previously subject to 
subpart W. These sources may require sampling ports to be installed or 
other modifications to accommodate measurements required in 40 CFR 
98.233.
    The EPA agrees that the proposed provisions in 40 CFR 98.235(e) and 
(f) should be extended to all subpart W emission sources, because 
issues that make it unreasonable to perform measurements for new wells 
may also exist for other subpart W emission sources. Therefore, we are 
finalizing these provisions to more broadly apply to ``sources'' rather 
than ``wells.''
    The EPA disagrees that the proposed provisions in 40 CFR 98.235(f) 
should be extended to sources acquired from other companies that were 
previously subject to subpart W. The reporting rule general provisions 
in 40 CFR 98.4(h) provide for changes in owners and operators and 
provide that such owner or operator shall be responsible for the 
representations, actions, inactions, and submissions of the designated 
representative and any alternate designated representative of the 
facility or supplier. Therefore, reporters are responsible for 
gathering data in a timely manner for acquired sources. Also, for 
sources acquired from companies that were previously subject to subpart 
W, any necessary sampling ports or other modifications would have 
previously been made to the equipment to accommodate measurement. 
Because facilities typically spend several months planning the 
acquisition and installation of new equipment, we anticipate that any 
issues can be addressed during this time, before the equipment begins 
to operate.
    While we are not extending the missing data provisions proposed in 
40 CFR 98.235(e) and (f) to facilities already subject to subpart W, we 
acknowledge that there are special cases where new compressors can be 
added to an existing facility and it may not be possible to perform an 
``as found'' measurement of that new compressor source during the 
calendar year, for example, if the compressor is installed in late 
December. To address this issue, we have revised the proposed 
amendments for compressors at 40 CFR 98.233(o)(1)(i) and (p)(1)(i) to 
not require annual measurements of compressors installed after annual 
compressor measurements have already been conducted for all existing 
compressors at the facility. If not all of the existing compressors at 
the facility have been measured, then there is no additional burden 
associated with identifying and scheduling a testing crew for measuring 
the newly installed compressor. However, if a facility has already 
conducted their annual compressor measurements, requiring measurement 
of emissions for the newly installed compressor would impose a 
significant additional burden and may not be logistically possible 
within the calendar year. Therefore, in today's final rule, an annual 
measurement of a newly installed compressor would not be required if 
annual compressor measurements have already been conducted for all 
existing compressors at the facility. In this case, no missing data 
provisions are needed or are applicable for these newly installed 
compressors.
    Comment: Several commenters took issue with the provisions in 40 
CFR 98.235(h) and portions of related reporting requirements in 40 CFR 
98.236(bb). The commenters objected to reporting a description of the 
unique or unusual circumstance that led to missing data use and a 
description of how the owner or operator will avoid the use of missing 
data in the future. The commenters argued that this would create an 
unneeded burden on reporters, go beyond the requirements of a reporting 
program, and are an overreach of the EPA's authority. Other industries 
subject to Part 98 are not required to this level of detail. One 
commenter also asserted that aggregation of missing data values is 
appropriate.
    Response: Reporting elements for the missing data provisions are 
necessary for the EPA to understand what missing data substitute values 
were used; however, we agree with the commenter that the level of 
detail required in the proposed reporting requirements could become 
burdensome, especially for continuously monitored parameters. We 
reviewed the reporting requirements associated with the use of missing 
data procedures in the general provision 40 CFR 98.3(c)(8) and other 
subparts in Part 98. Although we disagree that the proposed missing 
data reporting requirements go beyond the requirements of a reporting 
program or is an overreach of the EPA's authority, we recognize that 
missing data can occur, such as due to calibration checks that indicate 
an instrument needs to be recalibrated. After considering the proposed 
reporting requirements in light of the comments received and the 
reporting provisions in other subparts, we determined that revisions 
were needed to the proposed missing data reporting requirements. In 
this final rule, we are requiring reporting of the use of missing data 
procedures following the general provision requirements in 40 CFR 
98.3(c)(8), except we are providing for the reporting of number of 
times missing data procedures were used for an element that is not 
based on continuously monitored parameters.
    Comment: One commenter noted that the missing data procedures 
proposed in 40 CFR 98.235(a) should be amended to accommodate new AGR 
vents that may not have four previously taken samples available. 
Another commenter indicated that 40 CFR 98.235(d) poses a problem where 
``before'' or ``after'' values are not available for a data element 
that requires measurement. The commenter asserted that instances where 
a ``before'' or ``after'' value is not available for substitution 
require additional flexibility to enable compliance. The commenter 
provided, as an example, a situation where information from a third-
party equipment operator, such as a third-party operated dehydrator, is 
not received and no data are available to substitute. The commenter 
also noted that there may be instances where a well completion in a 
sub-basin category/county/well-type combination is a single unique well 
and the measurement equipment necessary to measure flowback or 
calculate flowback malfunctions. The commenter argued that in this 
case, a reporter will not have ``before'' data to substitute.
    Response: With respect to the missing data procedures for AGR 
vents, we agree with the commenter that additional clarification is 
needed, particularly to address new AGR vents that do not have four 
previous quarterly samples. In considering potential clarifications for 
the missing data procedures for AGR vents in light of the various 
scenarios of data availability, the missing data procedures for this 
source mirrored the procedures proposed in 40 CFR 98.235(d). 
Furthermore, we determined that the use of the average of a ``before'' 
and ``after'' sample would provide as good an estimate of the missing 
data as the average of four ``before'' samples. Therefore, we are 
generalizing the proposed missing data procedures in 40 CFR 98.235(d) 
to apply to all measurements that are required to be performed 
quarterly or more frequently.
    The provisions proposed at 40 CFR 98.235(d) include specific 
provisions that can be used to determine the missing value in the 
absence of a ``before'' or ``after'' measurement. We find that the 
proposed procedures are reasonable for any data element that is

[[Page 70372]]

required to be monitored quarterly or more frequently. The proposed 
provisions of 40 CFR 98.235(d) are not meant to address measurement 
data that are required annually or biannually or situations such as the 
supply of information by third-party vendors. Reporters should know 
what information is needed for the annual reports. If reporters elect 
to use third-party vendors for certain services, the information needed 
for the annual reports may be specified in the third-party contract or 
agreement to ensure the necessary information is provided. We are not 
including any missing data provision in the final rule to allow for use 
of third-party operators that do not provide the required information 
needed for determining the emissions from dehydrators or other 
emissions sources.

D. Summary of Final Amendments to Best Available Monitoring Methods

1. Summary of Final Revisions
    In this final rule, the EPA is removing all prior provisions in 40 
CFR 98.234(f) for BAMM as proposed, but we are also adding transitional 
BAMM provisions for the 2015 calendar year after considering public 
comments. Specifically, we are revising 40 CFR 98.234(f) to provide 
short-term transitional BAMM for reporters who are subject to new 
monitoring or measurement requirements as part of these final 
amendments. Reporters have the option of using BAMM from January 1, 
2015, to March 31, 2015, for certain parameters that cannot reasonably 
be measured according to the monitoring and QA/QC requirements of 40 
CFR 98.234. Specifically, the transitional 2015 BAMM provisions cover 
the following data:
    <bullet> Well-related measurement data that cannot reasonably be 
measured for well venting for liquids unloading and gas well venting 
during well completions and workovers with hydraulic fracturing, from 
wells not previously measured.
    <bullet> Reciprocating compressor blowdown valve, isolation valve, 
and rod packing venting from manifolded vents, when conducting ``as 
found'' measurements according to revised 40 CFR 98.233(p)(4) or 
(p)(5).
    <bullet> Centrifugal compressor blowdown valve, isolation valve, 
and wet seal oil degassing venting from manifolded vents, when 
conducting ``as found'' measurements according to revised 40 CFR 
98.233(o)(4) or (o)(5).
    For these parameters, reporters have the option to use BAMM from 
January 1, 2015, to March 31, 2015, without seeking prior EPA approval. 
Reporters will also have the opportunity to request an extension for 
the use of BAMM beyond March 31, 2015; those owners or operators must 
submit a request to the Administrator by January 31, 2015. The EPA is 
not providing transitional BAMM for these revised requirements beyond 
December 31, 2015. The provision of 3 months of automatic transitional 
BAMM will allow reporters to prepare for data collection while 
automatically being able to use BAMM, which is consistent with BAMM 
schedules in prior Part 98 rulemakings. This additional time for 
reporters to comply with the revised monitoring methods in subpart W 
will allow facilities to install the necessary monitoring equipment 
during other planned (or unplanned) process unit downtime, thus 
avoiding process interruptions.
    We are also removing and reserving 40 CFR 98.234(g). As described 
in the preamble to the proposed rule, we intended to remove and reserve 
this section but the removal of this section was not included in the 
regulatory text. These removed provisions are specific to the 2011 and 
2012 reporting years, and the removal of this provision does not impact 
the reporting requirements for subsequent reporting years.
2. Summary of Comments and Responses
    This section summarizes the major comments and responses related to 
best available monitoring methods. See the 2014 response to comment 
document in Docket Id. No. EPA-HQ-OAR-2011-0512 for a complete listing 
of all comments and responses.
    Comment: Three commenters supported the removal of BAMM for natural 
gas distribution facilities beginning in the 2015 calendar year. One 
commenter stated that replacing BAMM with explicit reporting 
requirements for petroleum and natural gas systems will reduce 
transaction costs, improve compliance, improve access to information 
about the oil and gas sector, and increase confidence in the rule. A 
second commenter believed that by clarifying the reporting emissions 
from natural gas distribution facilities, there should be no need to 
use BAMM after January 1, 2015. A third commenter pointed out that BAMM 
was originally a transitional tool, and other industry-specific 
subparts of Part 98 have eliminated BAMM. The commenter stated that the 
use of BAMM in 2012 created difficulties in comparing data across 
facilities and understanding discrepancies between GHG and other 
inventories. The commenter supported the addition of expanded missing 
data procedures and compliance pathways for facilities to use in the 
future. The commenter suggested that if operators require more 
flexibility than the ones EPA has proposed, that flexibility should be 
incorporated through a rulemaking effort rather than BAMM requests.
    Eight commenters disagreed with the removal of BAMM beginning in 
the 2015 calendar year. Several commenters stated that eliminating BAMM 
would compromise compliance of impacted sources, especially in 
instances when it is not feasible to obtain a required measurement or 
where a direct measurement may be unsafe. These commenters requested 
the ongoing availability of BAMM or a revision of the missing data 
procedures for those instances where a reporter demonstrates a 
legitimate need.
    Commenters pointed out that access to alternative methods is 
necessary for regulations. Some of the commenters pointed out that the 
EPA has allowed alternative compliance and monitoring methods in other 
regulatory programs (e.g., NSPS in 40 CFR part 60, National Emission 
Standards for Hazardous Air Pollutants (NESHAP) in 40 CFR part 63, and 
the Acid Rain Program in 40 CFR part 75) and urged the EPA to create a 
replacement, such as robust missing data provisions, for BAMM if it is 
eliminated. Other commenters stated that subpart W includes additional 
and more complex measurements than other Part 98 source categories. 
Some commenters expressed the importance of BAMM for sources that 
subsequently become subject to GHG reporting or where unpredictable 
future events occur. One commenter considered the flexibility of 
alternative methods to be important in the development of new 
technology and asked that the EPA should consider allowances in those 
cases. The commenter provided example scenarios in which the commenter 
stated that BAMM or an alternative method should be required, although 
the scenarios are not necessarily ``unique or unusual,'' such as vent 
lines that are unsafe to access and are unable to be assessed with an 
acoustic device, operating modes that are rarely used, and facilities 
where a late year addition of a new source precludes the ability to 
gather data.
    Another commenter explained that future changes in operation or 
equipment may cause the facility to exceed the reporting threshold or 
create circumstances in which emission points meet the subpart W 
criteria, though that may not be known until the facility is surveyed. 
The commenter stated that

[[Page 70373]]

there may be time to resolve the situation before the monitoring 
deadline, but BAMM or a robust missing data provision would be needed. 
Two commenters asked that BAMM be allowed for newly acquired wells that 
were previously reported by prior owners and wells that have never 
reported, as both situations require the same level of effort to 
comply.
    Three commenters requested at least a 6-month transitional BAMM 
following the final rule. The commenters requested adequate time to 
implement changes following the final rule. One commenter stated that a 
transitional BAMM of 6 months would allow flexibility to reporters, 
provide time for clarifications, allow for the development for the 
required systems, and accommodate issues regarding situations beyond 
the facility's control which require BAMM. Another commenter stated 
that developing processes for monitoring data or activities that have 
never before been subject to federal or state reporting may take 
significant time and effort. The commenter pointed out that until the 
final rule has been issued, reporters will not be able to determine 
what is required and will not know if BAMM is needed. Another commenter 
stated that if BAMM is not extended, small operators without the 
resources to quickly implement the rule would be unfairly 
disadvantaged.
    Response: The EPA has considered the concerns raised by commenters 
in the development of this final rule. We are removing the prior BAMM 
requirements in 40 CFR 98.234(f) because we have determined that these 
provisions, which applied broadly to circumstances in which data 
collection methods did not meet safety regulations, were technically 
infeasible, or were counter to state, local, or federal regulations, 
are no longer necessary to comply with the final rule. As one commenter 
noted, BAMM was originally included in Part 98 as a transitional tool, 
and all other industry-specific subparts of Part 98 have eliminated 
BAMM from their monitoring options. The revisions in this final rule 
will resolve the need for BAMM for the scenarios mentioned above for 
subpart W and can, therefore, bring this subpart into alignment with 
the monitoring provisions in other industry-specific subparts by 
removing the current BAMM provisions. In the development of this final 
rule, the EPA reviewed BAMM request submittals for the 2014 reporting 
year. In our review, the EPA found that the sources with the most 
frequent BAMM requests included centrifugal compressors, reciprocating 
compressors, blowdown vent stacks, and combustion emissions, which are 
addressed in this rulemaking. The most common concerns raised in BAMM 
requests were associated with technical infeasibility including 
concerns related to having to shut down a facility to install access 
ports to conduct compressor measurements. Other concerns related to 
compressors routed to a flare, manifolded lines, and compressor vents 
that were unsafe or inaccessible to measure. As discussed in Section 
II.B.10 of this preamble, we are making several revisions in this final 
rule that will allow for the testing of these compressor vents. First, 
we are clarifying that operators do not have to shut a facility down 
for the sole purpose to test a compressor in its non-operating mode, 
but that the measurement must be made at the next scheduled shutdown 
that requires a compressor to be taken off-line for planned or 
scheduled maintenance. These provisions reduce the burden on reporters 
to schedule a shutdown solely for the purposes of conducting 
measurements. The EPA has also provided the option for facilities to 
conduct continuous measurements using a permanent meter. Next, we are 
providing for reporters to conduct a single annual ``as found'' 
measurement for manifolded compressors routed to a common vent, in lieu 
of a measurement for each individual compressor manifolded to the 
common vent. We are also allowing the use of an IR camera for pre-
screening of emissions from blowdown valves on compressors in operating 
mode or standby-pressurized mode and for isolation valves on 
compressors in not-operating-depressurized mode. The option to use an 
IR camera to screen for emissions, in addition to the current allowance 
for use of an acoustic measurement device, eases the burden on 
facilities with inaccessible or unsafe-to-measure valves. Finally, for 
compressors routed to a flare, we are finalizing provisions to allow 
operators to calculate and report emissions with other flare emissions. 
In this case, reporters are no longer required to sample compressors 
routed to a flare individually.
    The EPA is also addressing the most common scenarios for which BAMM 
was previously requested for other emission sources. For example, for 
blowdown vent emissions, the EPA previously approved BAMM requests for 
reporting data by unique physical volume. In this final rule, we are 
revising the reporting of blowdown emissions to aggregate emissions by 
equipment type, as discussed in Section II.B.6 of this preamble. 
Similarly, for well venting for liquids unloading, the final rule 
allows for annualizing of venting data to account for situations where 
it was not feasible to gather vent hours or the number of unloadings 
from all controllers on January 1 or December 31, and it provides 
alternatives to determining the shut-in pressure required in Equation 
W-8. We have incorporated revisions in this final rule to address BAMM 
concerns for onshore production tanks and well completions and 
workovers. Additionally, we are finalizing missing data procedures that 
add clarity and specificity in how to treat and report missing data, 
including continuous measurements, periodic measurements and activity 
data. These missing data procedures are not intended to replace BAMM, 
however, they provide clarity for reporters who may have 
unintentionally missed collecting required data. These missing data 
procedures would also apply to facilities for which changes in 
operation or equipment may cause the facility to exceed the reporting 
threshold or result in creating circumstances in which emission points 
meet the subpart W criteria, as well as for newly acquired sources that 
were not previously reported under subpart W. We also note that there 
have been previous BAMM requests in which facilities noted technical 
concerns including instances where equipment modifications or 
installations were necessary. By the 2015 reporting year, facilities 
will have had four years to implement any necessary changes in order to 
fully comply with subpart W, which we have determined to be sufficient 
time to make any equipment modifications or installations. Therefore, 
we are not including BAMM provisions for these scenarios in this final 
rule.
    Regarding the comment that other regulatory programs allow 
alternative compliance and monitoring methods, the EPA acknowledges 
that the provisions of NSPS and NESHAP allow facilities to request 
alternative monitoring and testing methods. However, the NSPS and 
NESHAP provisions typically require that specific monitoring methods be 
used (e.g. EPA Method 18 for gas compositional analysis), and they do 
not allow facilities to use alternative monitoring and testing methods 
without the method first being approved by the EPA. The EPA has 
provided a great deal of flexibility in the methods allowed in subpart 
W, such as certain provisions that allow the use of standard methods 
published by consensus-based standard organizations and that allow the 
use of

[[Page 70374]]

industry standard practice. Given the flexibility in the methods 
allowed under Part 98, we do not agree with the commenters.
    Although we are removing the current BAMM provisions of 40 CFR 
98.234(f), the final rule introduces new short-term transitional BAMM 
provisions for certain parameters for the 2015 calendar year. The EPA 
agrees with commenters that some facilities may need to obtain the 
necessary equipment to conduct measurements as required under the 
revised calculation methods in this final rule. Thus, under the final 
rule, reporters have the option of using BAMM for certain parameters 
that cannot be reasonably measured according to the monitoring and QA/
QC requirements of 40 CFR 98.234. For example, we are revising the 
emission estimation methods for well completions and workovers from 
wells with hydraulic fracturing to separate reporting by well 
completions and workovers and by the sub-basin and well-type 
combination. In some cases, we expect reporters will be required to 
measure existing wells of a well-type combination for which they have 
not previously reported separately. In this case, reporters have the 
option to use BAMM for well-related data (i.e., initial and average 
flowback rates for Calculation Method 1 or pressures upstream and 
downstream of the choke for Calculation Method 2). Other situations 
where the final rule provides an option to use BAMM in the 2015 
calendar year are for determining vented gas flow when using 
Calculation Method 1 to estimate emissions from liquids unloading, and 
for determining vented emissions from compressor sources that are 
manifolded.
    In some cases, although we are revising emissions calculation 
methods in the final rule, we are not providing the BAMM option because 
the underlying measurement methods have not changed. For example, 
although we have separated the calculation of emissions from 
completions and workovers from wells without hydraulic fracturing in 40 
CFR 98.233(h), reporters are still collecting the same well data and 
measurements. We are not providing BAMM in this case or in similar 
cases where reporters would not be required to change their data 
collection methods.
    We are not providing the BAMM option for parameters in revised 
calculation methods where the rule already provides alternatives to 
direct measurements. For example, the final rule requires facilities in 
the onshore natural gas transmission compression, underground natural 
gas storage, LNG storage, and LNG import export industry segments to 
report emissions from flares based on using the calculation methods for 
flare stacks. BAMM is not needed in this case because 40 CFR 
98.233(n)(1) specifies that flare gas flow may be estimated using 
engineering calculations based on process knowledge, company records, 
and best available data. Similarly, 40 CFR 98.233(n)(2) specifies that 
as an alternative to using a continuous gas composition analyzer on the 
flare gas, a reporter in the four industry segments now required to 
report flare emissions may use a representative composition determined 
by engineering calculation based on process knowledge and best 
available data. The BAMM option also is not being provided for activity 
data such as completion or workover counts and venting or operating 
time because the final rule does not specify monitoring equipment that 
must be used for measuring these parameters.
    The final rule allows reporters to use BAMM for the specified 
parameters during the January 1, 2015 to March 31, 2015 time period 
without seeking prior EPA approval. By automatically allowing BAMM 
until March 31, 2015, this schedule allows additional time following 
the publication of the final rule for reporters to prepare for data 
collection and install the necessary monitoring equipment. The final 
rule also provides for reporters the option to request an extension for 
the use of BAMM beyond March 31, 2015, but no further than December 31, 
2015. Reporters who request an extension must submit a request to the 
Administrator by January 31, 2015, and demonstrate to the 
Administrator's satisfaction that it is not reasonably feasible to 
acquire, install, and operate a required piece of monitoring equipment 
by April 1, 2015, to receive approval to use BAMM beyond March 31, 
2015. In these cases, the Administrator will only approve BAMM for the 
parameters specified in Section II.D.1 of this preamble. We anticipate 
that the number of BAMM requests approved for the 2015 calendar year 
will be limited and will not greatly impact the quality of the data 
collected in 2015.

E. Summary of Final Additions of New Data Elements and Revisions to 
Reporting Requirements

1. Summary of Final Revisions
    We are finalizing the addition of several data elements to 40 CFR 
98.236, with revisions from the proposed rule based on review of 
comments and other considerations. Although the EPA received comments 
objecting to the proposed addition of these data elements, these new 
data elements are based on data that are already collected by the 
reporter or are readily available to the reporter. The reporting of 
these data elements will improve the quality of the data reported, 
improve the verification of reported emissions, and reduce the amount 
of correspondence with reporters that is associated with follow-up and 
revision of annual reports.
    After proposal, we determined that some proposed data elements 
could be removed to lessen reporter burden. For offshore production 
facilities, the final rule requires reporting of the total quantity of 
oil handled at the offshore platform, which includes the quantity from 
blended oil/condensate streams; this reporting element replaces the 
proposed requirements to report the amount of oil and the amount of 
condensate separately. Additionally, we are not finalizing the proposed 
requirements to report the model name, description, and installation 
year for each compressor.
    As a result of comments received on the proposed rule, we are 
adding requirements to report two data elements for centrifugal and 
reciprocating compressors. Affected facilities with centrifugal or 
reciprocating compressors will be required to indicate whether the 
measured volume of flow from the compressor includes blowdown 
emissions, according to 40 CFR 98.236(o)(4)(iii) and 40 CFR 98.236 
(p)(4)(iii), respectively.
2. Summary of Comments and Responses
    This section summarizes the major comments and responses related to 
the addition of new reporting requirements in 40 CFR 98.236(aa). See 
the 2014 response to comment document in Docket Id. No. EPA-HQ-OAR-
2011-0512 for a complete listing of all comments and responses.
    Comment: One commenter questioned the proposal's requirements to 
report information that does not address emissions but instead requires 
ancillary information such as compressor ratings. The commenter 
considered these new measurement and reporting requirements to go 
beyond the authority of the EPA under CAA Sections 114 and 208, making 
the changes arbitrary and capricious if finalized. The commenter 
considered the proposed reporting requirement changes to be an 
overreach for an emissions reporting program and points out that 40 CFR 
98.236(aa) in particular appears to be using Part 98 as a vehicle to 
construct detailed profile of

[[Page 70375]]

the oil and gas production sector. The commenter considered the 
proposed changes to unnecessarily expand the measurements and reporting 
requirements from the existing Part 98 and points out examples.
    Multiple commenters provided examples of data elements that they 
stated are not within the scope of Part 98 because they are not 
directly related to emissions quantification or are redundant: For 
transmission storage tank vent stack, whether scrubber dump leakage is 
occurring for the underground storage vent--Sec.  98.236(k)(l)(iii); 
year compressor was installed--Sec.  98.236(p)(1)(xiv); compressor 
model name and description-- Sec.  98.236(p)(1)(xv); date of last rod 
packing--Sec.  98.236(p)(1)(xvi); average time surveyed components were 
found leaking and operational--Sec.  98.236(q)(2)(iii); average 
upstream pipeline pressure, psig--Sec.  98.236(aa)(4)(iv); average 
downstream pipeline pressure, psig--Sec.  98.236(aa)(4)(v); quantity of 
gas injected into storage--Sec.  98.236(aa)(5)(i); quantity of gas 
withdrawn from storage--Sec.  98.236(aa)(5)(ii); number of 
compressors--Sec.  98.236(aa)(4)(ii); total compressor power rating for 
all compressors combined, hp--Sec.  98.236(aa)(4)(iii); and total 
storage capacity for underground natural gas storage facilities--Sec.  
98.236(aa)(5)(iii).
    One commenter stated that the EPA should explain or justify the 
need for addition of these data elements. Multiple commenters stated 
that the new reporting requirements are not relevant for quantifying 
emissions and developing this information in order to report represents 
a substantial burden.
    Response: The EPA disagrees with commenters that the proposed data 
elements are beyond the authority of the EPA under CAA section 114. CAA 
section 114 authorizes the EPA to gather the information under this 
rule. Specifically, section 114 provides for the gathering of 
information from direct sources of GHG emissions, as long as that 
information is for purposes of carrying out any provision of the CAA. 
CAA section 208 applies to mobile sources, which are not covered by 
subpart W.
    The additional reporting requirements included in this final rule 
provide production, capacity, and operational information for sources 
subject to subpart W and are similar to the data collected under other 
subparts of Part 98. These data elements are useful for the 
verification of existing data. For example, production, capacity, or 
operational information may be used to normalize the data collected and 
adequately characterize emissions sources. Therefore, the EPA is 
finalizing these reporting requirements as proposed, with minor 
clarifications. Further information on the final changes to the 
reporting section may be found in the memorandum, ``Final Revisions to 
the Subpart W Reporting Requirements in the ``Greenhouse Gas Reporting 
Rule: 2014 Revisions and Confidentiality Determinations for Petroleum 
and Natural Gas Systems; Final Rule'' in Docket Id. No. EPA-HQ-OAR-
2011-0512.

III. Confidentiality Determinations

A. Summary of Final Confidentiality Determinations for New or Revised 
Subpart W Data Elements

    In the proposed rule, we assigned new or revised data elements to 
the appropriate direct emitter data categories created in the 2011 
Final CBI Rule based on the type and characteristics of each data 
element. For data elements the EPA assigned to a direct emitter 
category with a categorical determination, the EPA proposed that the 
categorical determination for the category be applied to the proposed 
new or revised data element. For data elements assigned to the ``Unit/
Process `Static' Characteristics that Are Not Inputs to Emission 
Equations'' and ``Unit/Process Operating Characteristics that Are Not 
Inputs to Emission Equations,'' we proposed confidentiality 
determinations on a case-by-case basis taking into consideration the 
criteria in 40 CFR 2.208, consistent with the approach used for data 
elements previously assigned to these two data categories. We also 
proposed individual confidentiality determinations for 11 new or 
substantially revised data elements without making a data category 
assignment and we proposed to revise the confidentiality determination 
for one existing subpart W data element. Refer to the preamble to the 
proposed rule (79 FR 13394, March 10, 2014) for additional information 
regarding the proposed confidentiality determinations.
    With consideration of the data provided by commenters, the EPA is 
finalizing the confidentiality determinations as proposed for all but 7 
of the new and substantially revised data elements that were proposed. 
Specifically, the EPA is finalizing the proposed decision to require 
each of the new data elements and the one existing data element for 
which we revised the confidentiality determination be designated as 
``not CBI'', with the exception of seven new data elements for which we 
have subsequently identified potential confidentiality concerns, as 
discussed in this section. The seven data elements with revised 
confidentiality determinations apply to onshore natural gas plants and 
natural gas transmission facilities.
    For onshore natural gas plants, the EPA has revised the 
determination for the following four data elements: The quantity of 
natural gas received at the gas processing plant in the calendar year 
(reported under 40 CFR 98.236(aa)(3)(i)), the quantity of processed 
(residue) gas leaving the gas processing plant (reported under 40 CFR 
98.236(aa)(3)(ii)), the quantity of natural gas liquids (NGL) (bulk and 
fractionated) received (reported under 40 CFR 98.236(aa)(3)(iii)), and 
the quantity of NGL (bulk and fractionated) leaving the plant (reported 
under 40 CFR 98.236(aa)(3)(iv)). In the proposal, we indicated that we 
designated the annual quantity of natural gas received at a gas plant 
and the annual quantity of residue gas leaving a gas plant to be ``not 
CBI'' because the average annual flow and plant utilization rate are 
published on the Energy Information Administration's (EIA's) Web site 
and are already in the public domain. However, upon reexamination we 
determined that reporting to EIA of the amount of natural gas received 
is less frequent than that required under subpart W and we have not 
identified any reliable public sources of the quantity of residue gas 
produced. Thus, we have decided to maintain the annual quantity of 
natural gas received at gas plants and the annual quantity of processed 
(residue) gas leaving gas plants as confidential.
    We indicated in the proposal that the two NGL data elements were 
aggregated values for all NGL received and all NGL supplied by a 
natural gas processing plant. We also explained that this information 
would not cause competitive harm to reporters because the data for 
individual NGL products (which would be likely to cause competitive 
harm) would not be disclosed. While most plants receive and supply 
several different NGL products, we have identified a few plants that 
receive and/or supply only one NGL product. For example, some plants 
remove only ethane from the natural gas received. For this subset of 
plants, the quantity to be reported under subpart W is identical to the 
quantity reported under subpart NN, which the EPA determined to be CBI 
(see 76 FR 30782, May 26, 2011). Thus, the EPA has decided not to make 
a confidentiality determination for 40 CFR 98.236(aa)(3)(iii) and 
(aa)(3)(iv).

[[Page 70376]]

The confidentiality status of these data elements will be evaluated on 
a case-by-case basis, in accordance with the existing CBI regulations 
in 40 CFR part 2, subpart B, upon receipt of a public request for these 
data elements.
    For the natural gas transmission sector, the EPA has revised the 
confidentiality determination in this action for three data elements: 
The quantity of gas transported through a compressor station (reported 
under 40 CFR 98.236(aa)(4)(i)) and the average upstream and downstream 
pressures (reported under 40 CFR 98.236(aa)(4)(iv) and (v), 
respectively). We proposed that these data elements be designated as 
``not CBI.'' We noted that the natural gas transmission sector was 
heavily regulated by the Federal Energy Regulatory Commission (FERC) 
and state commissions due to a lack of competition between companies. 
We further noted that FERC controls pricing, sets rules for business 
practices, and is responsible for approving the location, construction, 
and operations of companies operating in this sector. However, we 
received comments from this industry sector noting that FERC Order 636 
had introduced greater competition to this sector and that some 
companies charge customers less than the FERC approved rates because of 
competitive market pressures. The three data elements identified above 
would provide information on the quantity of gas transported by a 
specific pipeline. This information may potentially cause competitive 
harm to some pipeline companies operating in more competitive market 
areas. Since the determination would depend on the particular market 
conditions for each company, the EPA was not able to make a 
determination for these data elements that would apply for all 
reporters. Thus, the EPA has decided not to make a confidentiality 
determination for 40 CFR 98.236(aa)(4)(i), (iv) and (v). The 
confidentiality status of these data elements will be evaluated on a 
case-by-case basis, in accordance with the existing CBI regulations in 
40 CFR part 2, subpart B, upon receipt of a public request for these 
data elements.
    The EPA received several comments questioning the proposed 
determination that several new or revised data elements should be 
treated as non-confidential. Specifically, we received comments 
requesting that the EPA classify certain data elements associated with 
exploratory wells (delineation and wildcat wells) as CBI for a period 
of at least 24 months from the start of exploration. These comments and 
the EPA's responses are summarized in Section III.B of this preamble. 
Based on consideration of these comments and consistent with the EPA's 
previous decisions related to exploratory wells under Part 98 (79 FR 
63750, October 24, 2014), the EPA is revising the final rule to provide 
reporters with the option to delay reporting of 12 data elements for 
two reporting years in situations where exploratory wells are the only 
wells in a sub-basin. For a given sub-basin, in situations where 
wildcat wells and/or delineation wells are the only wells in a sub-
basin that can be used for the required measurement, the following data 
elements associated with the delineation or wildcat well may be delayed 
for two reporting years: (1) Cumulative flowback time for each sub-
basin (40 CFR 98.236(g)(5)(i)); (2) measured flowback rate for each 
sub-basin (40 CFR 98.236(g)(5)(ii)); (3) average daily gas production 
rate for all completions without hydraulic fracturing in the sub-basin 
without flaring (40 CFR 98.236(h)(1)(iv)); (4) average daily gas 
production rate for all completions without hydraulic fracturing in the 
sub-basin with flaring (40 CFR 98.236(h)(2)(iv)); (5) if using 
Calculation Method 1 or 2 for atmospheric storage tanks, the total 
annual gas-liquid separator oil volume that is sent to atmospheric 
storage tanks in the sub-basin, in barrels; (6) if using Calculation 
Method 3 for atmospheric storage tanks, the total annual oil throughput 
that is sent to atmospheric tanks in the basin (40 CFR 
98.236(j)(2)(i)(A)); (7) if oil well testing is not performed where 
emissions are not vented to a flare, the average flow rate in barrels 
of oil per day for well(s) tested (40 CFR 98.236(l)(1)(iv); (8) if oil 
well testing is performed where emissions are vented to a flare, the 
average flow rate in barrels of oil per day for well(s) tested (40 CFR 
98.236(l)(2)(iv)); (9) if gas well testing is performed where emissions 
are not vented to a flare, average annual production rate in actual 
cubic feet per day for well(s) tested (40 CFR 98.236(l)(3)(iii)); (10) 
if gas well testing is performed where emissions are vented to a flare, 
average annual production rate in actual cubic feet per day for well(s) 
tested. (40 CFR 98.236(l)(4)(iii)); (11) volume of oil produced in the 
calendar year during the time periods in which associated gas was 
vented or flared (40 CFR 98.236(m)(5)); and (12) total volume of 
associated gas sent to sales in the calendar year during time periods 
in which associated gas was vented or flared (40 CFR 98.236(m)(6))).
    Six of the 12 data elements for which reporting may be delayed by 2 
years are inputs to emission equations and the EPA provided the same 
option in the EPA's previous decisions related to exploratory wells 
under Part 98 (79 FR 63750, October 24, 2014). Five of the 12 data 
elements are inputs only when the applicable data are related to a 
single well (40 CFR 98.236(g)(5)(i), (h)(1)(iv), (h)(2)(iv), (m)(5), 
and (m)(6)), and one data element is never an input (40 CFR 
98.236(j)(2)(i)(A)). The EPA decided to treat all early disclosure 
concerns related to exploratory wells consistently throughout subpart W 
by providing the option to delay reporting by 2 years to all 12 data 
elements. For the six data elements that are not always inputs, the 
finalized confidentiality determinations of ``not CBI'' apply in 
situations where the data elements are not an input to an equation. 
Specifically, the ``not CBI'' determination applies to all situations 
that involve multiple non-exploratory wells or a mix of exploratory and 
non-exploratory wells, and the ``not CBI'' determinations also will 
apply to data elements related to multiple exploratory wells once the 
data are reported to the EPA following the 2 year delay. For the 
situations when the data elements are used as inputs to equations, the 
EPA is assigning them to the ``Inputs to Emission Equations'' data 
category and is not making confidentiality determinations for these 
data.
    In response to public comments, the EPA has added eight new data 
elements related to compressors as reporting requirements and has 
assigned them to the ``Unit/Process `Static' Characteristics That Are 
Not Inputs to Emission Equations'' data category. Two of the new data 
elements require reporters to indicate whether compressor blowdown 
emissions are included in the measured volume of flow from compressor 
sources that are monitored continuously. Four of the new data elements 
require reporters to indicate whether measurements for manifolded 
groups of compressor sources are located prior to or after comingling 
with non-compressor emissions. These six data elements apply to both 
centrifugal compressors and reciprocating compressors, and they are 
located in 40 CFR 98.236(o)(3)(i)(F), (o)(4)(iii), (o)(4)(iv), 
(p)(3)(i)(F), (p)(4)(iii), and (p)(4)(iv). For each centrifugal and 
reciprocating compressor equipped with blind flanges, the other two new 
data elements require reporters to provide the dates when the blind 
flanges were in place, and these elements are located in 40 CFR 
98.236(o)(1)(x) and (p)(1)(xii). All eight of the new data elements are 
the same type of data as other data elements included in this category 
in

[[Page 70377]]

the March 2014 proposal such as the data element that requires 
reporters to indicate whether any compressor source emissions are 
routed to a flare. Like other data elements in this category, the new 
data elements do not vary with time or with the operation of the 
compressor. Additionally, the new data elements describe only an aspect 
of the compressor design and emissions handling technique that reveals 
no sensitive information that would be likely to cause substantial harm 
to any type of natural gas facility. The March 2014 proposal addressed 
the same type of data elements. We conclude that it is appropriate to 
assign the data elements to this data category and finalize our 
determination that these data elements are ``not CBI'' in this action.
    The EPA has determined that we inadvertently omitted proposing 
confidentiality determinations for 12 new data reporting elements. The 
measured scrubber dump valve leak rate vented directly to atmosphere 
(40 CFR 98.236(k)(2)(ii)), the measured scrubber dump valve leak rate 
vented to flare (40 CFR 98.236(k)(3)(ii)), and the annual 
CO<INF>2</INF> and CH<INF>4</INF> emissions from above grade metering-
regulating stations that are not above grade transmission-distribution 
transfer stations (40 CFR 98.236(r)(2)(v)(A) and (r)(2)(v)(B), 
respectively) are data representing emissions to the atmosphere. The 
March 2014 proposal addressed numerous similar elements and assigned 
them to the ``Emissions'' data category, which has a categorical 
confidentiality determination of ``not CBI.'' We conclude that it is 
appropriate to assign the four previously omitted data elements to the 
``Emissions'' data category and finalize our determination that these 
data elements are ``not CBI'' in this action.
    Five of the new data elements for which we did not propose 
confidentiality determinations in the proposed rule are similar to data 
elements that were assigned to the ``Unit/Process Operating 
Characteristics That are Not Inputs to Emission Equations'' data 
category. For example, the type of control device for emissions from 
glycol dehydrators with an annual average daily natural gas throughput 
less than 0.4 MMscf per day (40 CFR 98.236(e)(2)(iii)) is the same as 
the data element in 40 CFR 98.236(e)(3)(i) for reporting the type of 
control device used to control emissions from dehydrators that use 
desiccant. The number of atmospheric tanks in the sub-basin that did 
not control emissions with flares (40 CFR 98.236(j)(2)(ii)(B)) and the 
number of atmospheric tanks in the sub-basin that controlled emissions 
with flares (40 CFR 98.236(j)(2)(iii)(B)) are comparable to the data 
elements in 40 CFR 98.236(e)(2) and (e)(3) for the counts of 
dehydrators that vent to atmosphere, flare, vapor recovery, or other 
types of control devices. The duration of time that a scrubber dump 
valve leak occurred (40 CFR 98.236(k)(2)(iii)) and the duration of time 
that flaring of a scrubber dump valve leak occurred (40 CFR 
98.236(k)(3)(iii)) are comparable to the data element in 40 CFR 
98.236(j)(3)(ii) for the total time that dump valves on gas-liquid 
separators did not close properly. Furthermore, as we noted in the 
discussion of the confidentiality determination for 40 CFR 
98.236(j)(3)(ii) in the preamble to the proposed rule, because the time 
period during which a dump valve is malfunctioning provides little 
insight into maintenance practices or the nature or cost of repairs 
that are needed, public disclosure of such information would not be 
likely to cause substantial competitive harm to reporters. The 
finalized confidentiality determinations for all of the data elements 
that are comparable to the five data elements that were inadvertently 
omitted from the analysis at proposal are ``not CBI.'' We conclude that 
it is appropriate to assign the five previously omitted data elements 
to the ``Unit/Process Operating Characteristics That are Not Inputs to 
Emission Equations'' data category and finalize our determination that 
these data elements are ``not CBI'' in this action.
    Three of the new data elements for which we did not propose 
confidentiality determinations in the proposed rule are identical to 
other data elements that were included in the analysis at proposal. The 
centrifugal compressor name or ID (40 CFR 98.236(o)(2)(i)(A)), the 
centrifugal compressor source (40 CFR 98.236(o)(2)(i)(B)), and the 
unique name or ID for the leak or vent (40 CFR 98.236(o)(2)(i)(C)) are 
identical to the corresponding data elements for reciprocating 
compressors in 40 CFR 98.236(p)(2)(i)(A), (p)(2)(i)(B), and 
(p)(2)(i)(C). These data elements for reciprocating compressors were 
assigned to the ``Facility and Unit Identifier Information'' data 
category, and the final confidentiality determination for these data 
elements is ``not CBI.'' We conclude that it is appropriate to assign 
the three previously omitted data elements to the ``Facility and Unit 
Identifier Information'' data category and finalize our determination 
that these data elements are ``not CBI'' in this action.
    As discussed in Section II.B.5 of this preamble, the final rule 
clarifies the reporting requirements for the time variable used in 
Equation W-10A (40 CFR 98.236(g)(5)(i)). Specifically, the final rule 
requires reporting of both cumulative gas flowback time values used in 
the revised Equation W-10A (``T<INF>p,i</INF>'' and 
``T<INF>p,s</INF>''), whereas the proposed rule inadvertently retained 
the current reporting of the single value that is used in Equation W-
10A from the subpart W 2010 final rule. At proposal, the data element 
was determined to be an input. However, it is an input only when one 
completion or workover has been conducted in a particular sub-basin and 
well type combination category. When data for completions or workovers 
for multiple wells are included in the calculation, it is a data 
element for which a confidentiality determination is required. The 
final data elements in 40 CFR 98.236(g)(5)(i) are similar to the data 
element in 40 CFR 98.236(h)(2)(iii) for reporting the total number of 
hours of venting during completions without hydraulic fracturing. We 
assigned the data element in 40 CFR 98.236(h)(2)(iii) to the ``Unit/
Process Operating Characteristics That are Not Inputs to Emission 
Equations'' data category and proposed a confidentiality determination 
of ``not CBI'' because the cumulative venting time for multiple 
completions or workovers would not disclose information on individual 
wells and is not likely to cause substantial competitive harm. For the 
same reasons, we conclude that it is appropriate to assign the data 
elements in 40 CFR 98.236(g)(5)(i), in the cases where they are not 
inputs to equations (i.e., when data for more than one well are used in 
Equation W-10A), to the ``Unit/Process Operating Characteristics That 
are Not Inputs to Emission Equations'' data category and finalize our 
determination that these data elements are ``not CBI'' in this action. 
In the situations where these data elements are used as an input to an 
equation, we are assigning them to the ``Inputs to Emission Equations'' 
data category and not making a confidentiality determination for these 
data.
    In the final rule, the EPA has also edited for clarity numerous 
reporting elements based on public comments. Portions of 40 CFR 98.236 
also were rearranged to improve clarity in the final rule. These edits 
did not change the type of data to be reported and, thus, the 
confidentiality determinations do not need to be reassessed. All of the 
changes are documented in the Memorandum ``Final Revisions to the 
Subpart W Reporting Requirements in the `Greenhouse Gas Reporting Rule:

[[Page 70378]]

2014 Revisions and Confidentiality Determinations for Petroleum and 
Natural Gas Systems; Final Rule' '' in Docket Id. No. EPA-HQ-OAR-2011-
0512.

B. Summary of Comments and Responses

    This section summarizes the major comments and responses related to 
the proposed categorical assignments and confidentiality 
determinations. See the 2014 response to comment document in Docket Id. 
No. EPA-HQ-OAR-2011-0512 for a complete listing of all comments and 
responses. See the memorandum ``Final Data Category Assignments and 
Confidentiality Determinations for Data Elements (excluding inputs to 
emission equations) in the `Greenhouse Gas Reporting Rule: 2014 
Revisions and Confidentiality Determinations for Petroleum and Natural 
Gas Systems; Final Rule' '' in Docket Id. No. EPA-HQ-OAR-2011-0512 for 
a complete listing of final data category assignments and 
confidentiality determinations, and a discussion of changes since 
proposal.
    Comment: Two commenters disagreed with the EPA's statement that the 
natural gas transmission industry is ``inherently uncompetitive'' or 
``less competitive than other industries.'' One commenter pointed out 
that although interstate natural gas pipeline rates are established on 
a cost-of-service basis by FERC, the FERC-issued Order 636 has fostered 
a competitive culture by unbundling pipeline merchant and 
transportation services. The commenter argued that pipelines face 
multiple forms of competition which affect service offerings and 
prices, including: Competition with alternative fuels, competition 
between gas supply basins, and competition among pipelines. The 
commenter argued that pipelines sometimes charge customers less than 
the FERC-approved maximum tariff rate due to competitive market 
conditions. Another commenter stated that they operate in markets in 
which other natural gas pipeline companies regularly compete for 
pipeline business through discounting and other competitive market 
practices. Both commenters stated that the release of specific 
operational data could result in substantial harm to a pipeline 
operator's competitive position.
    Response: The EPA agrees with commenters that Order 636 did 
increase competition. We note, however, that many of the data elements 
are already publicly available from other sources. The number of 
compressors (reported under 40 CFR 98.236(aa)(4)(ii)) and the total 
compressor power rating (reported under 40 CFR 98.236(aa)(4)(iii)) are 
also available to the public through state and federal construction and 
operating permits and FERC. The quantity of gas injected into 
underground storage (reported under 40 CFR 98.236(aa)(5)(i)), the 
quantity of gas withdrawn from underground storage (reported under 40 
CFR 98.236(aa)(5)(ii)), the quantity of LNG injected into storage 
(reported under 40 CFR 98.236(aa)(8)(ii)), the quantity of LNG 
withdrawn from storage (reported under 40 CFR 98.236(aa)(8)(ii), the 
total underground storage capacity (reported under 40 CFR 
98.236(aa)(5)(iii)) and the total LNG storage capacity (reported under 
40 CFR 98.236(aa)(8)(iii)) are reported annually to the EIA on forms 
EIA-176 (Annual Report of Natural and Supplemental Gas Supply) and EIA-
191 (Monthly Underground Gas Storage Report). The EIA publishes this 
data on their Web site.\2\ Since these data elements are already in the 
public domain, they are not entitled to confidential treatment under 40 
CFR 2.208. We are therefore finalizing as proposed the determination 
that these data elements are ``not CBI.''
---------------------------------------------------------------------------

    \2\ See the EIA Natural Gas Annual Respondent Query System at 
http://www.eia.gov/cfapps/ngqs/ngqs.cfm?f_report=RP7.
---------------------------------------------------------------------------

    We have not identified any reliable public sources for the 
following data elements: The quantity of gas transported through a 
compressor station (reported under 40 CFR 98.236(aa)(4)(i)) and the 
average upstream and downstream pressures (reported under 40 CFR 
98.236(aa)(4)(iv) and (v), respectively). These data elements provide 
information on the quantity of gas transported by a specific pipeline 
and disclosure of this data may potentially cause competitive harm to 
some pipeline companies operating in more competitive market areas. 
Since the determination would depend on the particular market 
conditions for each company, the EPA was not able to make a 
determination for these data elements that would apply for all 
reporters. Thus, the EPA has decided not to make a confidentiality 
determination for 40 CFR 98.236(aa)(4)(i), (iv) and (v). The 
confidentiality status of these data elements will be evaluated on a 
case-by-case basis, in accordance with the existing CBI regulations in 
40 CFR part 2, subpart B, upon receipt of a public request for these 
data elements.
    Comment: One commenter supported classifying as CBI, information in 
40 CFR 98.236(d)(1)(iv) on whether any CO<INF>2</INF> emissions from 
the AGR unit are recovered and transferred outside the facility. The 
commenter stated that the data element is directly linked to multiple 
data elements associated with industrial CO<INF>2</INF> production 
plants and import/exporter of CO<INF>2</INF> that have been previously 
determined to be CBI under subpart PP (Suppliers of Carbon Dioxide).
    Response: The EPA has reviewed the data element referenced by the 
commenter. The EPA notes that 40 CFR 98.236(d)(1)(iv) includes two data 
elements. First, reporters must indicate whether CO<INF>2</INF> 
emissions are recovered from the AGR units and transferred offsite (as 
proposed). Second, reporters must supply the quantity of CO<INF>2</INF> 
emissions that are collected and transferred offsite. The second data 
element in the proposed rule inadvertently removed text stating that 
reporters should report this information under subpart PP. It would be 
redundant to report the quantity of CO<INF>2</INF> emissions that are 
collected and transferred offsite under both subpart PP and subpart W. 
In this final rule, we are providing that if any CO<INF>2</INF> 
emissions from the AGR unit were recovered and transferred outside the 
facility, then the facility must report the annual quantity of 
CO<INF>2</INF> that was recovered and transferred outside the facility 
under subpart PP.
    Thus, the proposed rule only included one new data element 
(``Whether any CO<INF>2</INF> emissions are recovered and transferred 
outside the facility'') for which a confidentiality determination was 
proposed. The EPA has determined that the data element is not the same 
data element as reported under subpart PP. Therefore, we are finalizing 
as proposed our determination that the data element is ``not CBI.'' The 
EPA disagrees with the commenters' assertion that the proposed 
determination for ``whether CO<INF>2</INF> emissions are recovered from 
the AGR units and transferred offsite'' is inconsistent with the 
determination made for data elements reported under subpart PP. None of 
the data elements reported under subpart PP are similar to this data 
element. The determinations for subpart PP were made with regard to 
quantities of CO<INF>2</INF> from production wells and to the 
quantities of CO<INF>2</INF> collected and transferred offsite from 
industrial production facilities. Furthermore, this data element 
reveals only that the facility has an AGR unit (currently publicly 
available in permits) and that CO<INF>2</INF> is collected as a 
byproduct and transferred offsite. Since the CO<INF>2</INF> is only a 
by-product of the process, the EPA has determined that disclosure of 
this information would not cause substantial competitive harm.
    Comment: Five commenters requested that the EPA review 
confidentiality

[[Page 70379]]

determinations for consistency with data elements that are found in 
both subpart NN and subpart W. Several of these commenters provided 
citations in subpart NN for data elements that have been given a 
determination of CBI which also appear in 40 CFR 98.236(aa)(3)(i) 
through 40 CFR 98.236(aa)(3)(vii) in the proposed rule with a ``non-
CBI'' determination.
    Response: The EPA has reviewed the confidentiality determinations 
for subparts W and NN and has determined that two data elements in 
subpart NN have confidentiality determinations that are inconsistent 
with those proposed for subpart W. The first is the quantity of natural 
gas withdrawn from storage in a calendar year (reported under 40 CFR 
98.236(aa)(5)(i)), which was proposed to be ``not CBI'' for all 
underground storage operators. Under subpart NN, local distribution 
companies report the volume of natural gas withdrawn from on-system 
storage and the annual volume of LNG withdrawn from storage and 
vaporized for delivery on the distribution system (40 CFR 
98.406(b)(3)), for which we previously made a determination of CBI. 
However, review of publicly available data undertaken during the 
preparation of the proposal for this action found that gas withdrawals 
from underground storage are reported to the EIA on form EIA-176 
(Annual Report of Natural And Supplemental Gas Supply and Disposition). 
As we noted in the proposal, the EIA considers all information 
submitted on EIA-176 to be non-proprietary information and publishes 
the quantity of natural gas withdrawn from storage on their Web site. 
Since the quantity of natural gas withdrawn from storage is publicly 
available, this data element is not entitled to confidential treatment 
under the provisions in 40 CFR 2.208. The EPA notes that this final 
rule relates to calculation and reporting requirements for subpart W 
and not subpart NN, and therefore inconsistencies with respect to 
subpart NN are not addressed by this rule.
    The second data element is the quantity of gas received at a gas 
processing plant (reported by natural gas processing plants under 40 
CFR 98.236(aa)(3)(i)), which we proposed as ``not CBI.'' Plants that 
fractionate natural gas into its constituent NGL are required to report 
the volume of natural gas received by their plant for processing (see 
40 CFR 40 CFR 98.406(a)(3)). In a previous notice, we determined that 
the data element required by 40 CFR 98.406(a)(3) was entitled to 
confidential treatment under 40 CFR 2.208 because it provided 
information regarding raw material consumption that we believed was not 
already in the public domain and could potentially cause competitive 
harm if disclosed. During the preparation of the proposal for this 
action, the EPA found that detailed plant-level information is reported 
by all natural gas plants to the EIA on Schedule A of form EIA-757 
(Natural Gas Processing Plant Survey) once every 3 years. The 
information reported includes the annual average natural gas flow in 
million cubic feet per day entering a natural gas plant (including 
plants that also fractionate natural gas). EIA considers the 
information on annual average natural gas flows entering a plant to be 
non-proprietary information that it makes available to the public. 
However, because the information reported to EIA is on a different 
frequency than that required under subpart W, we have determined that 
the quantity of natural gas received at a gas processing plant under 40 
CFR 98.236(aa)(3)(i) is entitled to confidential treatment under the 
provisions of 40 CFR 2.208. These data provide detailed information 
regarding the quantities of natural gas processed that would be likely 
to cause competitive harm if disclosed as it provides sensitive 
information on market share. Thus, in this final action we are changing 
the determination for 40 CFR 98.236(aa)(3)(i) from ``not CBI'' to 
``CBI.''
    The other data elements specifically mentioned by commenters are 
either not the same as those reported under subpart NN or they have 
determinations that are consistent with those in subpart NN. For 
example, commenters noted that the quantity of NGL (bulk and 
fractionated) received (reported under 40 CFR 98.236(aa)(3)(iii) and 
the quantity of NGL (bulk and fractionated) leaving the plant (reported 
under 40 CFR 98.236(aa)(3)(iv)) are the same as the data elements 
reported under 40 CFR 98.406(a)(2) and (a)(1), respectively. However, 
the commenters are mistaken. Under subpart W, the data elements 
reported are actually aggregated totals for all NGL products received 
and all NGL products supplied. Under subpart NN, facilities report the 
quantities of each individual product. The subpart NN data elements 
were previously determined to be entitled to confidential treatment 
because they provide detailed information regarding the quantities of 
individual products that would be likely to cause competitive harm if 
disclosed as it provides sensitive information on market share. Since 
the NGL data reported under subpart W is in an aggregated form, the 
quantities of individual products is not disclosed and therefore does 
not pose the same risk of causing competitive harm to the reporters. 
The only exception is in situations where the plant is known to receive 
or supply only one NGL product. In these situations, the EPA has 
decided not to make a confidentiality determination for 40 CFR 
98.236(aa)(3)(iii) and (aa)(3)(iv).
    Comment: One commenter expressed concern about reporting 
information on exploratory wells in subpart W, especially when the 
wells are located in step-out areas where no prior reporting exists for 
a given sub-basin (including vertical or horizontal wells). The 
commenter explained that the problem occurs when an exploratory well is 
the sole well in a sub-basin (including vertical or horizontal wells) 
and is not reported in combination with other wells, thereby shielding 
any individual well's contribution. The commenter noted that its 
concerns are related to the timing of releasing the information to the 
public, as the commenter stated that the information is most sensitive 
if it is made available too early during the exploration or initial 
development stages. The commenter stated that the success of a well in 
exploratory areas could be inferred if detailed data are provided to 
the public too soon during the exploration and assessment period. The 
commenter provided an example of such an occurrence: An exploratory 
well completed in December of the reporting year, data reported to the 
EPA by end of March of the following year and then released by the EPA 
to the public within a few months during the same year. The commenter 
stated that early release of data regarding operating characteristics 
of such wells, including post-flowback flaring/venting volumes, could 
cause competitive harm if made publicly available too early.
    The commenter noted that Federal law and State codes allow 
companies to designate as confidential the data obtained from 
exploratory wells, especially in new discovery areas or areas that are 
being explored for development. The commenter further noted that the 
original intent of State oil and gas commissions to allow withholding 
of select drilling and production information from early release to the 
public was to allow competitive exploration by searching for new 
pockets of oil or gas and experimenting with new tools and techniques. 
The commenter stated that releasing data on such wells through Part 
98--despite the fact that they are held confidential by other 
regulatory bodies--could cause substantial

[[Page 70380]]

competitive harm and lead to a loss of investment value. The commenter 
explained that competitive harm could occur if the public could obtain 
detailed high-resolution operational information on a well-by-well 
basis and on a daily or weekly basis.
    The commenter requested that the EPA categorically determine that 
all information associated with exploratory wells, with the exception 
of well ID and location, be classified as CBI for a period of at least 
24 months from the start of exploration. The commenter recommended 
either of two suggested approaches under Part 98: (1) Companies would 
report all data to the EPA as mandated by subpart W, but the EPA would 
hold the reported data as CBI and not include it in its public data 
release for at least 24 months (this could be accomplished by a 
flagging system (or a ``radio button'') in the Electronic Greenhouse 
Gas Reporting Tool that could also allow for a short informative text 
on why that particular well information is to be maintained 
confidential); or (2) the EPA could set up a deferral system where 
initial data on exploratory wells will be well ID and location 
information and the remaining data would be backfilled by companies 
after a period of 24 months. The commenter added that neither option 
would require case-by-case review of companies' information, and both 
are consistent with the approach taken by state oil and gas commissions 
and are protective of companies' commercial investment interests. The 
commenter identified the following data elements as potentially 
sensitive when reported for exploratory wells:
    <bullet> Sub-basin ID. (40 CFR 98.236(g)(1))
    <bullet> Well type. (40 CFR 98.236(g)(2))
    <bullet> Cumulative backflow time, in hours, for each sub basin. 
(40 CFR 98.236(g)(5)(i))
    <bullet> Vented natural gas volume, in standard cubic feet, for 
each well in the sub-basin. (40 CFR 98.236(g)(6))
    <bullet> Annual gas emissions, in standard cubic feet. (40 CFR 
98.236(g)(7))
    <bullet> For each sub-basin with gas well completions without 
hydraulic fracturing and without flaring, Sub-basin ID. (40 CFR 
98.236(h)(1)(i))
    <bullet> For each sub-basin with gas well completions without 
hydraulic fracturing and without flaring, average daily gas production 
rate for all completions without hydraulic fracturing in the sub-basin 
without flaring, in standard cubic feet per hour. (40 CFR 
98.236(h)(1)(iv))
    <bullet> For each sub-basin with gas well completions without 
hydraulic fracturing and with flaring, Sub-basin ID. (40 CFR 
98.236(h)(2)(i))
    <bullet> For each sub-basin with gas well completions without 
hydraulic fracturing and with flaring, average daily gas production 
rate for all completions without hydraulic fracturing in the sub-basin 
with flaring, in standard cubic feet per hour. (40 CFR 
98.236(h)(2)(iv))
    <bullet> At the basin level for atmospheric tanks where emissions 
were calculated using Calculation Method 3, the total annual oil 
throughput that is sent to atmospheric tanks in the basin, in barrels. 
(40 CFR 98.236(j)(2)(i)(A))
    <bullet> If oil well testing is performed where emissions are not 
vented to a flare, the average flow rate in barrels of oil per day for 
well(s) tested. (40 CFR 98.236(l)(1)(iv))
    <bullet> If oil well testing is performed where emissions are 
vented to a flare, the average flow rate in barrels of oil per day for 
well(s) tested. (40 CFR 98.236(l)(2)(iv))
    <bullet> If gas well testing is performed where emissions are not 
vented to a flare, the average annual production rate in actual cubic 
feet per day for well(s) tested. (40 CFR 98.236(l)(3)(iii))
    <bullet> If gas well testing is performed where emissions are 
vented to a flare, the average annual production rate in actual cubic 
feet per day for well(s) tested. (40 CFR 98.236(l)(4)(iii))
    <bullet> If associated gas was vented or flared during the calendar 
year, Sub-basin ID. (40 CFR 98.236(m)(1))
    <bullet> For each sub-basin, indicate whether any associated gas 
was vented without flaring. (40 CFR 98.236(m)(2))
    <bullet> For each sub-basin, indicate whether any associated gas 
was flared. (40 CFR 98.236(m)(3))
    <bullet> Volume of oil produced, in barrels, in the calendar year 
during the time periods in which associated gas was vented or flared. 
(40 CFR 98.236(m)(5))
    <bullet> Total volume of associated gas sent to sales, in standard 
cubic feet, in the calendar year during time periods in which 
associated gas was vented or flared. (40 CFR 98.236(m)(6))
    <bullet> Formation type. (40 CFR 98.236(aa)(1)(ii)(C))
    <bullet> For each sub-basin category, the number of producing wells 
at the end of the calendar year. (40 CFR 98.236(aa)(1)(ii)(D))
    <bullet> For each sub-basin category, the number of wells completed 
during the calendar year. (40 CFR 98.236(aa)(1)(ii)(G))
    <bullet> For offshore production, the quantity of gas produced from 
the offshore platform in the calendar year for sales. (40 CFR 
98.236(aa)(2)(i))
    Response: The EPA reviewed the data elements identified by the 
commenter as having disclosure concerns for exploratory wells 
(delineation wells and wildcat wells). After further investigation in 
response to the comment received, review of state laws protecting these 
types of data, and consistent with the EPA's previous decisions related 
to exploratory wells under Part 98 (79 FR 63750, October 24, 2014), the 
EPA has determined that, in the following situations which were not 
specifically considered in the proposed rule, early public disclosure 
of some of the data elements associated with wildcat wells and/or 
delineation wells could reveal the well productivity, thereby resulting 
in the loss of investment value:
    <bullet> For gas well completions or workovers with hydraulic 
fracturing, where wildcat wells and/or delineation wells are the only 
wells in a sub-basin that can be used for the measurement;
    <bullet> For gas well completions without hydraulic fracturing, 
where wildcat wells and/or delineation wells are the only wells in a 
sub-basin that can be used for the measurement;
    <bullet> For onshore production storage tanks, where wildcat wells 
and/or delineation wells are the only wells in a sub-basin or basin;
    <bullet> For well testing, where wildcat wells and/or delineation 
wells are the only wells in a sub-basin that are tested;
    <bullet> For associated gas venting and flaring, where wildcat 
wells and/or delineation wells are the only wells in a sub-basin;
    The data elements that could reveal well productivity for wildcat 
and/or delineation wells in the applicable situations listed above are 
as follows:
    <bullet> Cumulative flowback time, in hours, for each sub basin. 
(40 CFR 98.236(g)(5)(i))
    <bullet> For the measured well(s), the flowback rate, in standard 
cubic feet per hour, for each sub-basin. (40 CFR 98.236(g)(5)(ii))
    <bullet> For each sub-basin with gas well completions without 
hydraulic fracturing and without flaring, average daily gas production 
rate for all completions without hydraulic fracturing in the sub-basin 
without flaring, in standard cubic feet per hour. (40 CFR 
98.236(h)(1)(iv))
    <bullet> For each sub-basin with gas well completions without 
hydraulic fracturing and with flaring, average daily gas production 
rate for all completions without hydraulic fracturing in the sub-basin 
with flaring, in standard cubic feet per hour. (40 CFR 
98.236(h)(2)(iv))
    <bullet> At the sub-basin level for atmospheric tanks where 
emissions were calculated using Calculation Method 1 or 2, the total 
annual gas-

[[Page 70381]]

liquid separator oil volume that is sent to atmospheric storage tanks, 
in barrels. (40 CFR 98.236(j)(1)(iii))
    <bullet> At the basin level for atmospheric tanks where emissions 
were calculated using Calculation Method 3, the total annual oil 
throughput that is sent to atmospheric tanks in the basin, in barrels. 
(40 CFR 98.236(j)(2)(i)(A))
    <bullet> If oil well testing is performed where emissions are not 
vented to a flare, the average flow rate in barrels of oil per day for 
well(s) tested. (40 CFR 98.236(l)(1)(iv))
    <bullet> If oil well testing is performed where emissions are 
vented to a flare, the average flow rate in barrels of oil per day for 
well(s) tested. (40 CFR 98.236(l)(2)(iv))
    <bullet> If gas well testing is performed where emissions are not 
vented to a flare, the average annual production rate in actual cubic 
feet per day for well(s) tested. (40 CFR 98.236(l)(3)(iii))
    <bullet> If gas well testing is performed where emissions are 
vented to a flare, the average annual production rate in actual cubic 
feet per day for well(s) tested. (40 CFR 98.236(l)(4)(iii))
    <bullet> Volume of oil produced, in barrels, in the calendar year 
during the time periods in which associated gas was vented or flared. 
(40 CFR 98.236(m)(5))
    <bullet> Total volume of associated gas sent to sales, in standard 
cubic feet, in the calendar year during time periods in which 
associated gas was vented or flared. (40 CFR 98.236(m)(6))
    These 12 data elements are themselves a very small subset of data 
elements collected in subpart W. Further, wildcat and delineation wells 
represent a relatively small percentage of the wells being reported 
under Part 98 for these data elements. As a result, in the interim 
period before these data are reported to the EPA, the EPA will be able 
to verify the majority of the emissions using data elements that will 
be reported to the EPA. For the 12 data elements that may be delayed 
for 2 years, the EPA will verify emissions using other data reported to 
the EPA, and will conclude verification upon receipt of the data. The 
EPA agrees with the commenter that a two year delay of reporting is 
sufficient to prevent early public disclosure of these data and will 
provide sufficient time for the reporter to thoroughly conduct an 
assessment of the well. Given the results of this evaluation, the EPA 
determined that, for these 12 data elements, in those cases where a 
reporter has delineation wells or wildcat wells in cases where wildcat 
wells and/or delineation wells in a sub-basin and these wells meet one 
of the five situations described above, reporters should be provided an 
option to delay reporting of the given data element for two reporting 
years starting in 2015. In such cases, if the two-year delay in 
reporting is used, the reporter must report the following information 
in the current reporting year: indicate for each delayed reporting 
element that one of the five situations listed above is true (e.g., for 
gas well completions or workovers with hydraulic fracturing, wildcat 
wells and/or delineation wells are the only wells in a sub-basin that 
can be used for the measurement). In addition, when reporters report 
the delayed data elements to emission equations after the 2 year delay, 
they must also report the American Petroleum Institute (API) well ID 
numbers for the applicable wildcat and/or delineation wells in the sub-
basin for which the reporting element was delayed. For example, if a 
delineation or wildcat well is completed in 2015 in a sub-basin that 
has only delineation or wildcat wells or these are the only wells for 
which measurements can be made, then the reporter may (1) elect to 
report these 12 data elements in their 2015 annual report submitted by 
March 31, 2016; or (2) elect to delay reporting of these data elements 
for up to two years. If the reporter elects to delay reporting, then 
the API well ID numbers for the wildcat and delineation wells in the 
sub-basin for which reporting has been delayed must be reported by 
March 31, 2016 and the data elements delayed from reporting must be 
reported no later than March 31, 2018.
    The following data elements meet the definition of emission data in 
40 CFR 2.301(a)(2)(i) because they are actual volumes of gas emitted by 
the facility: volume of natural gas vented (reported under 40 CFR 
98.236(g)(6)) and annual gas emissions (reported under 40 CFR 
98.236(g)(7)). Under CAA section 114(c), the EPA must make available 
emission data, whether or not such data are CBI. For these data 
elements that are assigned to the ``Emissions'' data category, the 
commenter did not claim or provide any justification for why these data 
elements do not meet the definition of emission data.
    For the remaining data elements identified by the commenter as 
potentially sensitive with respect to delineation and wildcat wells, 
the EPA disagrees that public disclosure of these data elements in the 
time period following annual reporting would reveal well productivity, 
thereby resulting in the loss of investment value to the reporter. The 
sub-basin ID (reported under 40 CFR 98.236(g)(1), (h)(1)(i), (h)(2)(i), 
and (m)(1)) and number of wells can be discerned from the well IDs, 
which are publicly available for all wells and provide the location of 
the well and the name of the drilling company. Since the location of 
the well can be discerned from the well ID, the type of formation 
(reported under 40 CFR 98.236(aa)(1)(ii)(C)) can be determined through 
publicly available information such as U.S. Geological Survey reports. 
The well type (reported under 40 CFR 98.236(g)(2)), including whether 
hydraulic fracturing is used, can be inferred from the formation type. 
Similarly, although indicating whether the well vents or flares 
associated gas emissions (reported under 40 CFR 98.236(m)(2) and 
(m)(3)) identifies the well as an oil well, this information can also 
be concluded from the formation type, which, as previously mentioned, 
may be determined through publicly available information. The number of 
producing wells at the end of the calendar year (reported under 40 CFR 
98.236(aa)(1)(ii)(D)) and the number of wells completed during the 
calendar year (reported under 40 CFR 98.236(aa)(1)(ii)(G)) are reported 
for sub-basins with production wells. Information regarding production 
wells is available from state databases. Since these data elements are 
either not sensitive or can be easily inferred from information already 
in the public domain, the EPA has determined that release of this 
information would not result in competitive harm.

IV. Impacts of the Final Amendments to Subpart W

A. Impacts of the Final Amendments

    The final amendments to subpart W include technical corrections and 
revisions to the calculation, monitoring, and reporting requirements 
that do not significantly increase the burden of data collection and 
improve the accuracy of the data reported. In general, these revisions 
provide greater flexibility for reporters and increase the clarity and 
congruency of the calculation and reporting requirements. These final 
amendments do not impart significant additional burden to reporters and 
in some cases reduce burden to reporters and regulators.
    First, the following revisions to the calculation and monitoring 
requirements of subpart W are anticipated to decrease the burden or 
have no impact on the burden relative to the burden to comply with the 
current rule:
    <bullet> Allowing for the use of either site-specific composition 
data or a default gas composition for natural gas transmission 
compression, underground natural gas storage, LNG storage, LNG

[[Page 70382]]

import and export, and natural gas distribution facilities.
    <bullet> For well venting from liquids unloading, allowing the 
measurement period to differ slightly from the standard calendar year 
combined with annualizing the resulting venting data for facilities 
that calculate emissions using a recording flow meter.
    <bullet> Allowing for the option to use a site-specific 
compressibility factor for calculation of emissions from blowdown vents 
and for conversion of volumetric emissions at actual conditions to 
standard conditions.
    <bullet> Revising calculation methods for onshore production 
storage tanks to require quantification of emissions from well pad gas-
liquid separator liquid dump valves only if the dump valve is 
determined to not be closing properly.
    <bullet> Including a term to account for situations where part of 
the associated gas from a well goes to a sales line while another part 
of the gas is flared or vented. The term is already being calculated 
elsewhere and/or can be estimated.
    <bullet> Deciding against finalizing the addition of the term 
``ERE<INF>p,q</INF>'' for emissions reported under other sources; 
therefore, reporters will not be required to track these emissions.
    <bullet> Removing vented compressor emissions routed to a flare 
from the compressor emissions total and retaining the requirement to 
report uncontrolled vented emissions from compressors.
    <bullet> Addressing reporter concerns related to measuring 
centrifugal and reciprocating compressor emissions that are routed to a 
common vent manifold or flare header. Reporters were previously 
required to conduct emissions measurements for each individual 
compressor routed to the common vent. The final rule requires only a 
single annual emissions measurement at the common vent for groups of 
manifolded compressors. We are not finalizing the proposed requirement 
to conduct measurement of manifolded compressor source emissions before 
comingling with emissions from other sources.
    <bullet> Revising requirements to conduct measurements in the not-
operating-depressurized mode once every three years or at the next 
scheduled depressurized shutdown (for centrifugal compressors) or at 
the next scheduled shutdown when the compressor rod packing is replaced 
(for reciprocating compressors). We are not finalizing the proposed 
requirement to conduct testing in the operating-mode once every 3 
years.
    <bullet> Revising calculation methods for the natural gas 
distribution segment to clarify the calculation methodologies and 
reporting requirements for above grade metering-regulating stations.
    <bullet> Removing the existing best available monitoring method 
(BAMM) provisions in 40 CFR 98.234(f) and providing transitional BAMM 
for the 2015 calendar year. Removing the existing provisions does not 
add to previous burden estimates for subpart W reporters; these 
estimates were prepared based on all reporters complying with the 
monitoring methods in 40 CFR 98.234 without BAMM. The transitional BAMM 
included in this final rule would allow facilities to obtain the 
necessary equipment to conduct measurements as required under the 
revised calculation methods in this final rule, and would not add to 
the burden estimates included in the proposed rule. (See further 
discussion in Section II.D of this preamble.)
    <bullet> Providing for the use of optical gas imaging as a 
screening tool to detect emissions from reciprocating and centrifugal 
compressors; measurement to quantify the emissions is required only if 
the screening detects emissions.
    <bullet> Providing clarified, specific missing data procedures that 
provide guidance for reporters when a measurement is inadvertently 
missed.
    Second, the following revisions to the calculation, monitoring, and 
reporting requirements of subpart W slightly increase the burden 
relative to the burden to comply with the current rule:
    <bullet> Revising the calculation and reporting requirements for 
completions and workovers to differentiate between completions and 
workovers with different well type combinations in each sub-basin 
category.
    <bullet> Revising the calculation and reporting requirements for 
onshore natural gas transmission compression, underground natural gas 
storage, LNG storage, and LNG import and export to include emissions 
from flare stacks.
    Finally, the following revisions to the reporting requirements for 
subpart W do increase the burden of data collection, but not 
significantly. As further discussed in Section II of this preamble, the 
EPA is finalizing the addition of 247 new data elements, while 
substantially revising 13 data elements and deleting 34 data elements 
that were required to be reported under Part 98. Although not 
previously required to be reported, many of these data elements are 
typically already collected by reporters, related to data that are 
already being reported, or are readily available to reporters. For 
example, some of the new reporting elements are required for use in 
subpart W equations used to calculate emissions and others are 
collected to differentiate between identical equipment types.
    These final additions improve the quality of the data reported by 
removing ambiguity for the reporter and do not increase burden 
significantly, since the reporting elements are already available.
    The EPA received multiple comments regarding the impacts of the 
proposed amendments. After evaluating these comments and reviewing 
other changes from proposal, the EPA revised the impacts assessment. 
The final amendments to subpart W are not expected to significantly 
increase burden. See the memorandum, ``Assessment of Impacts of the 
2014 Final Revisions to Subpart W'' in Docket Id. No. EPA-HQ-OAR-2011-
0512 for additional information.

B. Summary of Comments and Responses

    This section summarizes the major comments and responses related to 
the impacts of the proposed amendments to subpart W of Part 98. See the 
2014 response to comment document in Docket Id. No. EPA-HQ-OAR-2011-
0512 for a complete listing of all comments and responses.
    Comment: Several commenters stated that the EPA significantly over-
simplified the impacts and underestimated the burden associated with 
the proposed rule. Specifically, commenters expressed concern that EPA 
has significantly underestimated the additional time and cost burden of 
the expanded reporting requirements. One commenter considered the 
implementation cost to be underestimated by an order of magnitude or 
more, providing an estimate of an additional $150,000 per company or 
more to initially identify, collect, document and report the new data 
elements with another $100,000 per year. This commenter critiqued the 
``Assessment of Impacts of 2014 Proposed Revisions to Subpart W'' and 
the information collection request (ICR) Supporting Statement and 
stated that many of the time and cost burdens should be much higher 
than the numbers included in these documents. The commenter stated that 
the cost estimates do not include management tasks including review of 
the proposed rule and final revisions, monitoring plan revisions, 
internal communications, coordination with technical staff, training, 
systems updates, or associated budgeting and planning. One concern was 
the assumption that 3 minutes would be required to find, document, and 
report each new data element. The

[[Page 70383]]

commenter pointed out that the estimate does not consider the level of 
effort required to determine who collects the data or how and where it 
is documented. Another commenter reported that their company had 
invested in a robust system to manage data collection and reporting 
according to the original rule requirements, and the revised changes 
would be burdensome and costly.
    Response: Although the commenter did not elaborate on the 
assumptions used to calculate the $150,000 initial cost or the $100,000 
annual cost, the EPA disagrees with the magnitude of these costs. 
Overall, the EPA has determined that the cost estimates provided by the 
commenters do not take into consideration the completion of one-time 
activities that occurred in the first year of data collection. In the 
EPA's cost estimates, we assumed the startup costs would be incurred 
during the first year of reporting, i.e., the 2011 reporting year. 
These costs included the labor burden of planning, registration, and 
installing required equipment to comply with the rule, as well as the 
initial costs of developing a data tracking system.
    The EPA maintains that allowing 3 minutes per data element is 
accurate. All new reporting elements are related to emission sources 
for which information is already being gathered and reported under 
subpart W. The new elements include such information as the name or ID 
of the emission source, measurement dates, installation dates, 
maintenance dates, equipment counts, measurement counts, operating 
hours, etc. Most, if not all, of these elements can be gathered at the 
same time as required measurements are being taken.
    Comment: One commenter stated that the EPA cost analysis 
incorrectly assumes an incremental time of 10 minutes for a technician 
to conduct each additional compressor source measurement for manifolded 
compressors. The commenter stated that this estimate fails to consider 
the time required to move personnel and equipment from compressor to 
compressor and the cautious pace of work and work practices (e.g., use 
of lanyard and/or other fall protection) for safely working at elevated 
locations. The commenter also pointed out that the measurement estimate 
appears to assume that the technician is working alone, reiterating 
that personnel do not work alone at elevated locations. The commenter 
further asserted that the EPA's burden estimate for compressor testing 
appears to include costs only for the testing contractor and does not 
include facility and company costs including scheduling, coordination, 
and test team support. The commenter stated that the proposed rule 
fails to account for costs associated with three separate measurements.
    Response: The original burden estimate referenced by the commenter 
was an adjustment to the burden estimate for the subpart W 2010 final 
rule to reflect the proposed changes for manifolded compressors. For 
manifolded compressors, the EPA proposed that reporters may measure 
downstream of the manifold, in lieu of measuring each compressor source 
individually. Therefore, the measurement burden estimates assumed that 
the technician would be taking a single measurement at the manifold and 
that the level of effort associated with manifolded measurements are 
similar to the level of effort associated with measurements for 
individual compressors.
    Additionally, in this final rule, we are specifying that ``as 
found'' measurements from manifolded compressors be taken one time per 
year instead of three separate measurements per year as proposed.

V. Statutory and Executive Order Reviews

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

    This action is not a ``significant regulatory action'' under the 
terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is 
therefore not subject to review under Executive Orders 12866 and 13563 
(76 FR 3821, January 21, 2011).
    In addition, the EPA prepared an analysis of the potential costs 
and benefits associated with the final amendments to subpart W. This 
analysis is contained in the memorandum ``Assessment of Impacts of the 
2014 Final Revisions to Subpart W.'' A copy of the analysis is 
available in the docket for this action (see Docket Id. No. EPA-HQ-OAR-
2011-0512) and the analysis is briefly summarized in Section IV of this 
preamble.

B. Paperwork Reduction Act

    The information collection requirements in this final rule have 
been submitted for approval to the Office of Management and Budget 
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The ICR 
document prepared by the EPA has been assigned OMB control number 2060-
0629 and EPA ICR tracking number 2300.15.
    This action simplifies the existing reporting methods in subpart W, 
clarifies monitoring methods and data reporting requirements, and 
finalizes confidentiality determinations for reported data elements. 
The EPA is restructuring the reporting requirements for clarity and to 
align them with the calculation requirements by adding 247 new data 
elements, substantially revising 13 data elements, and deleting 34 data 
elements.
    OMB has previously approved the information collection requirements 
for 40 CFR part 98 under the provisions of the Paperwork Reduction Act, 
44 U.S.C. 3501 et seq., and has assigned OMB control number 2060-0629 
and EPA ICR tracking number 2300.12. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9. Burden is 
defined at 5 CFR 1320.3(b).
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
    The information collection will result in an overall increase in 
annual burden of approximately 7,700 hours and $600,000. The estimated 
total projected cost and hour burden associated with reporting for 
subpart W are approximately $22,024,000 and 244,000 hours, 
respectively. For the hour burden, the estimated average burden hours 
per response is 53.7 hours, the frequency of response is once annually, 
and the estimated number of likely respondents is 2,885. These 
amendments to subpart W affect the labor costs, not the capital costs 
and operation and maintenance (O&M) costs. Therefore, the estimated 
total capital and start-up cost of monitoring equipment and related 
facility/process modifications annualized over the expected useful life 
of the equipment remains at $796,000 per year, and the total O&M cost 
remains at $1,690,000 per year. The total labor cost is $19,538,000 per 
year for all of subpart W.

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.

[[Page 70384]]

    For purposes of assessing the impacts of today's final rule on 
small entities, small entity is defined as: (1) A small business as 
defined by the Small Business Administration's regulations at 13 CFR 
121.201; (2) a small governmental jurisdiction that is a government of 
a city, county, town, school district or special district with a 
population of less than 50,000; and (3) a small organization that is 
any not-for-profit enterprise which is independently owned and operated 
and is not dominant in its field.
    This action (1) amends monitoring and calculation methodologies in 
subpart W; (2) amends reporting requirements; (3) assigns subpart W 
data reporting elements into CBI data categories; and (4) amends a 
definition in subpart A. After considering the economic impacts of 
these final rule amendments on small entities, I certify that this 
action will not have a significant economic impact on a substantial 
number of small entities. The small entities directly regulated by this 
final rule include small businesses in the petroleum and gas industry, 
small governmental jurisdictions and small non-profits. The EPA has 
determined that some small businesses would be affected because their 
production processes emit GHGs exceeding the reporting threshold.
    This action includes final amendments that do not result in a 
significant burden increase on subpart W reporters. In some cases, the 
EPA is increasing flexibility in the selection of methods used for 
calculating GHGs, and is also revising certain methods that may result 
in greater conformance to current industry practices. In addition, the 
EPA is revising specific provisions to provide clarity on what 
information is being reported. These revisions would not significantly 
increase the burden on reporters while maintaining the data quality of 
the information being reported to the EPA.
    Although this final rule will not have a significant economic 
impact on a substantial number of small entities, the EPA nonetheless 
has tried to reduce the impact of this rule on small entities. As part 
of the process of finalizing the subpart W 2010 final rule, the EPA 
took several steps to evaluate the effect of the rule on small 
entities. For example, the EPA determined appropriate thresholds that 
reduced the number of small businesses reporting. In addition, the EPA 
supports a ``help desk'' for the rule, which is available to answer 
questions on the provisions in the rule. Finally, the EPA continues to 
conduct significant outreach on the GHG reporting rule and maintains an 
``open door'' policy for stakeholders to help inform the EPA's 
understanding of key issues for the industries.

D. Unfunded Mandates Reform Act (UMRA)

    This rule contains no 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, this rule is 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 
(1) amends monitoring and calculation methodologies in subpart W; (2) 
amends reporting requirements, (3) assigns subpart W data reporting 
elements into CBI data categories; and (4) amends a definition in 
subpart A. The rule applies to few, if any, small governments. 
Therefore, this action is not subject to the requirements of section 
203 of the UMRA.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have 
substantial direct effects on the States, on the relationship between 
the national government and the States, or on the distribution of power 
and responsibilities among the various levels of government, as 
specified in Executive Order 13132. However, for a more detailed 
discussion about how Part 98 relates to existing state programs, please 
see Section II of the preamble to the final Part 98 rule (74 FR 56266, 
October 30, 2009).
    Few, if any, state or local government facilities would be affected 
by the provisions in this 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.

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

    Subject to the Executive Order 13175 (65 FR 67249, November 9, 
2000) the EPA may not issue a regulation that has tribal implications, 
that imposes substantial direct compliance costs, and that is not 
required by statute, unless the federal government provides the funds 
necessary to pay the direct compliance costs incurred by tribal 
governments, or the EPA consults with tribal officials early in the 
process of developing the proposed regulation and develops a tribal 
summary impact statement.
    The EPA has concluded that this action may have tribal 
implications. However, it will neither impose substantial new direct 
compliance costs on tribal governments, nor preempt Tribal law. This 
regulation would apply directly to petroleum and natural gas facilities 
that emit GHGs. Although few facilities that would be subject to the 
rule are likely to be owned by tribal governments, the EPA has sought 
opportunities to provide information to tribal governments and 
representatives during the development of the proposed and final 
subpart W that was promulgated on November 30, 2010 (75 FR 74458). The 
EPA consulted with tribal officials early in the process of developing 
subpart W to permit them to have meaningful and timely input into its 
development.
    For additional information about the EPA's interactions with tribal 
governments, see Section IV.F of the preamble to the re-proposal of 
subpart W published on April 12, 2010 (75 FR 18608), and Section IV.F 
of the preamble to the subpart W 2010 final rule published on November 
30, 2010 (75 FR 74458).

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

    The 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 104-113 (15 U.S.C. 272 note) directs 
the 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

[[Page 70385]]

standards (e.g., materials specifications, test methods, sampling 
procedures, and business practices) that are developed or adopted by 
voluntary consensus standards bodies. NTTAA directs EPA to provide 
Congress, through OMB, explanations when the Agency decides not to use 
available and applicable voluntary consensus standards. This action 
does not involve the use of any new technical standards. No changes are 
being finalized that affect the test methods currently in use for 
subpart W. Although the EPA is revising this final rule to allow for 
the use of additional measurement methods (optical gas imaging 
instrument) for pre-screening of compressor valve leakage, these 
revisions rely on existing technical standards in subpart W for similar 
emission sources. Therefore, the EPA is not considering the use of any 
new 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.
    The EPA has determined that this 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. Instead, this rule addresses information collection and 
reporting procedures.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996, generally 
provides that before a rule may take effect, the agency promulgating 
the rule must submit a rule report, which includes a copy of the rule, 
to each House of the Congress and to the Comptroller General of the 
United States. The EPA will submit a report containing this rule and 
other required information to the U.S. Senate, the U.S. House of 
Representatives, and the Comptroller General of the United States prior 
to publication of the rule in the Federal Register. A major rule cannot 
take effect until 60 days after it is published in the Federal 
Register. This action is not a ``major rule'' as defined by 5 U.S.C. 
804(2). This rule will be effective on January 1, 2015.

List of Subjects in 40 CFR Part 98

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

    Dated: November 13, 2014.
Gina McCarthy,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, of the 
Code of Federal Regulations is amended as follows:

PART 98--MANDATORY GREENHOUSE GAS REPORTING

0
1. The authority citation for part 98 continues to read as follows:

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

Subpart A--GENERAL PROVISIONS

0
2. Section 98.6 is amended by revising the definition of ``Well 
completions'' to read as follows:


Sec.  98.6  Definitions.

* * * * *
    Well completions means the process that allows for the flow of 
petroleum or natural gas from newly drilled wells to expel drilling and 
reservoir fluids and test the reservoir flow characteristics, steps 
which may vent produced gas to the atmosphere via an open pit or tank. 
Well completion also involves connecting the well bore to the 
reservoir, which may include treating the formation or installing 
tubing, packer(s), or lifting equipment, steps that do not 
significantly vent natural gas to the atmosphere. This process may also 
include high-rate flowback of injected gas, water, oil, and proppant 
used to fracture and prop open new fractures in existing lower 
permeability gas reservoirs, steps that may vent large quantities of 
produced gas to the atmosphere.
* * * * *

Subpart W--PETROLEUM AND NATURAL GAS SYSTEMS

0
3. Section 98.230 is amended by revising paragraph (a)(2) 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, engines, 
boilers, heaters, flares, separation and processing equipment, and 
portable non-self-propelled equipment, which includes well drilling and 
completion equipment, workover 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, 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. Onshore petroleum and natural gas production also means all 
equipment on or associated with a single enhanced oil recovery (EOR) 
well pad using CO<INF>2</INF> or natural gas injection.
* * * * *

0
4. Section 98.232 is amended by:
0
a. Revising paragraphs (c)(11), (d)(1), and (e)(1);
0
b. Adding paragraph (e)(6);
0
c. Revising paragraph (f)(1) and adding paragraph (f)(4);
0
d. Revising paragraph (g)(1) and adding paragraph (g)(4);
0
e. Revising paragraph (h)(1) and adding paragraph (h)(5); and
0
f. Revising paragraphs (i)(1) through (i)(7).
    The revisions and additions read as follows:


Sec.  98.232  GHGs to report.

* * * * *
    (c) * * *
    (11) Reciprocating compressor venting.
* * * * *
    (d) * * *
    (1) Reciprocating compressor venting.
* * * * *
    (e) * * *
    (1) Reciprocating compressor venting.
* * * * *
    (6) Flare stack emissions.
    (f) * * *
    (1) Reciprocating compressor venting.
* * * * *
    (4) Flare stack emissions.
* * * * *
    (g) * * *
    (1) Reciprocating compressor venting.
* * * * *
    (4) Flare stack emissions.
    (h) ** * *
    (1) Reciprocating compressor venting.
* * * * *

[[Page 70386]]

    (5) Flare stack emissions.
    (i) * * *
    (1) Equipment leaks from connectors, block valves, control valves, 
pressure relief valves, orifice meters, regulators, and open-ended 
lines at above grade transmission-distribution transfer stations.
    (2) Equipment leaks at below grade transmission-distribution 
transfer stations.
    (3) Equipment leaks at above grade metering-regulating stations 
that are not above grade transmission-distribution transfer stations.
    (4) Equipment leaks at below grade metering-regulating stations.
    (5) Distribution main equipment leaks.
    (6) Distribution services equipment leaks.
    (7) Report under subpart W of this part the emissions of 
CO<INF>2</INF>, CH<INF>4</INF>, and N<INF>2</INF>O emissions from 
stationary fuel combustion sources following the methods in Sec.  
98.233(z).
* * * * *

0
5. Section 98.233 is amended by:
0
a. Revising the introductory text;
0
b. Revising paragraphs (a) introductory text, (a)(1), and (a)(2) and 
adding paragraph (a)(4);
0
c. Revising paragraphs (c), (d), (e), (f), (g), (h), and (i);
0
d. Revising paragraphs (j) introductory text, (j)(1) introductory text, 
(j)(1)(vii) introductory text, and (j)(2);
0
e. Removing paragraphs (j)(3) and (j)(4);
0
f. Redesignating paragraphs (j)(5) through (j)(9) as paragraphs (j)(3) 
through (j)(7) and revising newly redesignated paragraphs (j)(3) 
through (j)(7);
0
g. Revising paragraphs (k), (l), (m), (n), (o), (p), (q), and (r);
0
h. Revising paragraphs (s)(2) introductory text, (s)(2)(i), (s)(3), and 
(s)(4);
0
i. Revising paragraphs (t) introductory text, (t)(1), and (t)(2);
0
j. Revising paragraphs (u) introductory text and (u)(2)(iii) through 
(vii);
0
k. Revising paragraphs (v), (w) introductory text, (w)(1), and (w)(3) 
introductory text;
0
l. Revising the parameters ``Mass<INF>CO2</INF>,'' ``N,'' and 
``V<INF>v</INF>'' to Equation W-37 in paragraph (w)(3);
0
m. Revising the introductory text of paragraph (x) and paragraph 
(x)(1);
0
n. Revising the parameter ``S<INF>hl</INF>'' to Equation W-38 in 
paragraph (x)(2);
0
o. Revising paragraph (z)(1);
0
p. Revising the parameters ``V<INF>a</INF>,'' ``Y<INF>CO2</INF>,'' 
``Y<INF>j</INF>,'' and ``Y<INF>CH4</INF>'' to Equations W-39A and W-39B 
in paragraph (z)(2)(iii);
0
q. Revising Equation W-40 in paragraph (z)(2)(vi) and the parameters 
``Mass<INF>N2O</INF>,'' ``Fuel,'' and ``HHV'' to Equation W-40 in 
paragraph (z)(2)(vi);
0
r. Removing the parameter ``GWP'' of Equation W-40 in paragraph 
(z)(2)(vi).
    The revisions and additions read as follows:


Sec.  98.233  Calculating GHG emissions.

    You must calculate and report the annual GHG emissions as 
prescribed in this section. For calculations that specify measurements 
in actual conditions, reporters may use a flow or volume measurement 
system that corrects to standard conditions and determine the flow or 
volume at standard conditions; otherwise, reporters must use average 
atmospheric conditions or typical operating conditions as applicable to 
the respective monitoring methods in this section.
    (a) Natural gas pneumatic device venting. Calculate CH<INF>4</INF> 
and CO<INF>2</INF> volumetric emissions from continuous high bleed, 
continuous low bleed, and intermittent bleed natural gas pneumatic 
devices using Equation W-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.026

Where:

E<INF>s,i</INF> = Annual total volumetric GHG emissions at standard 
conditions in standard cubic feet per year from natural gas 
pneumatic device vents, of types ``t'' (continuous high bleed, 
continuous low bleed, intermittent bleed), for GHG<INF>i</INF>.
Count<INF>t</INF> = Total number of natural gas pneumatic devices of 
type ``t'' (continuous high bleed, continuous low bleed, 
intermittent bleed) as determined in paragraph (a)(1) or (a)(2) of 
this section.
EF<INF>t</INF> = Population emission factors for natural gas 
pneumatic device vents (in standard cubic feet per hour per device) 
of each type ``t'' listed in Tables W-1A, W-3, and W-4 of this 
subpart for onshore petroleum and natural gas production, onshore 
natural gas transmission compression, and underground natural gas 
storage facilities, respectively.
GHG<INF>i</INF> = For onshore petroleum and natural gas production 
facilities, onshore natural gas transmission compression facilities, 
and underground natural gas storage facilities, concentration of 
GHG<INF>i</INF>, CH<INF>4</INF> or CO<INF>2</INF>, in produced 
natural gas or processed natural gas for each facility as specified 
in paragraphs (u)(2)(i), (iii), and (iv) of this section.
T<INF>t</INF> = Average estimated number of hours in the operating 
year the devices, of each type ``t'', were operational using 
engineering estimates based on best available data. Default is 8,760 
hours.

    (1) For all industry segments, determine ``Count<INF>t</INF>'' for 
Equation W-1 of this subpart for each type of natural gas pneumatic 
device (continuous high bleed, continuous low bleed, and intermittent 
bleed) by counting the devices, except as specified in paragraph (a)(2) 
of this section. The reported number of devices must represent the 
total number of devices for the reporting year.
    (2) For the onshore petroleum and natural gas production industry 
segment, you have the option in the first two consecutive calendar 
years to determine ``Count<INF>t</INF>'' for Equation W-1 of this 
subpart for each type of natural gas pneumatic device (continuous high 
bleed, continuous low bleed, and intermittent bleed) using engineering 
estimates based on best available data.
* * * * *
    (4) Calculate both CH<INF>4</INF> and CO<INF>2</INF> mass emissions 
from volumetric emissions using calculations in paragraph (v) of this 
section.
* * * * *
    (c) Natural gas driven pneumatic pump venting. (1) Calculate 
CH<INF>4</INF> and CO<INF>2</INF> volumetric emissions from natural gas 
driven pneumatic pump venting using Equation W-2 of this section. 
Natural gas driven pneumatic pumps covered in paragraph (e) of this 
section do not have to report emissions under this paragraph (c).
[GRAPHIC] [TIFF OMITTED] TR25NO14.059



[[Page 70387]]


Where:

E<INF>s,i</INF> = Annual total volumetric GHG emissions at standard 
conditions in standard cubic feet per year from all natural gas 
driven pneumatic pump venting, for GHG<INF>i</INF>.
Count = Total number of natural gas driven pneumatic pumps.
EF = Population emissions factors for natural gas driven pneumatic 
pumps (in standard cubic feet per hour per pump) listed in Table W-
1A of this subpart for onshore petroleum and natural gas production.
GHG<INF>i</INF> = Concentration of GHG<INF>i</INF>, CH<INF>4</INF>, 
or CO<INF>2</INF>, in produced natural gas as defined in paragraph 
(u)(2)(i) of this section.
T = Average estimated number of hours in the operating year the 
pumps were operational using engineering estimates based on best 
available data. Default is 8,760 hours.

    (2) Calculate both CH<INF>4</INF> and CO<INF>2</INF> mass emissions 
from volumetric emissions using calculations in paragraph (v) of this 
section.
    (d) Acid gas removal (AGR) vents. For AGR vents (including 
processes such as amine, membrane, molecular sieve or other absorbents 
and adsorbents), calculate emissions for CO<INF>2</INF> only (not 
CH<INF>4</INF>) vented directly to the atmosphere or emitted 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 methods described in this paragraph 
(d), as applicable.
    (1) Calculation Method 1. If you operate and maintain a continuous 
emissions monitoring system (CEMS) that has both a CO<INF>2</INF> 
concentration monitor and volumetric flow rate monitor, you must 
calculate CO<INF>2</INF> emissions under this subpart by following the 
Tier 4 Calculation Method and all associated calculation, quality 
assurance, reporting, and recordkeeping requirements for Tier 4 in 
subpart C of this part (General Stationary Fuel Combustion Sources). 
Alternatively, you may follow the manufacturer's instructions or 
industry standard practice. If a CO<INF>2</INF> concentration monitor 
and volumetric flow rate monitor are not available, you may elect to 
install a CO<INF>2</INF> concentration monitor and a volumetric flow 
rate monitor that comply with all of the requirements specified for the 
Tier 4 Calculation Method in subpart C of this part (General Stationary 
Fuel Combustion Sources). The calculation and reporting of 
CH<INF>4</INF> and N<INF>2</INF>O emissions is not required as part of 
the Tier 4 requirements for AGR units.
    (2) Calculation Method 2. If a CEMS is not available but a vent 
meter is installed, use the CO<INF>2</INF> composition and annual 
volume of vent gas to calculate emissions using Equation W-3 of this 
section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.060


Where:

E<INF>a,CO2</INF> = Annual volumetric CO<INF>2</INF> emissions at 
actual conditions, in cubic feet per year.
V<INF>S</INF> = Total annual volume of vent gas flowing out of the 
AGR unit in cubic feet per year at actual conditions as determined 
by flow meter using methods set forth in Sec.  98.234(b). 
Alternatively, you may follow the manufacturer's instructions or 
industry standard practice for calibration of the vent meter.
Vol<INF>CO2</INF> = Annual average volumetric fraction of 
CO<INF>2</INF> content in vent gas flowing out of the AGR unit as 
determined in paragraph (d)(6) of this section.

    (3) Calculation Method 3. If a CEMS or a vent meter is not 
installed, you may use the inlet or outlet gas flow rate of the acid 
gas removal unit to calculate emissions for CO<INF>2</INF> using 
Equations W-4A or W-4B of this section. If inlet gas flow rate is 
known, use Equation W-4A. If outlet gas flow rate is known, use 
Equation W-4B.
[GRAPHIC] [TIFF OMITTED] TR25NO14.027


Where:

E<INF>a, CO2</INF> = Annual volumetric CO<INF>2</INF> emissions at 
actual conditions, in cubic feet per year.
V<INF>in</INF> = Total annual volume of natural gas flow into the 
AGR unit in cubic feet per year at actual conditions as determined 
using methods specified in paragraph (d)(5) of this section.
V<INF>out</INF> = Total annual volume of natural gas flow out of the 
AGR unit in cubic feet per year at actual conditions as determined 
using methods specified in paragraph (d)(5) of this section.
Vol<INF>I</INF> = Annual average volumetric fraction of 
CO<INF>2</INF> content in natural gas flowing into the AGR unit as 
determined in paragraph (d)(7) of this section.
Vol<INF>o</INF> = Annual average volumetric fraction of 
CO<INF>2</INF> content in natural gas flowing out of the AGR unit as 
determined in paragraph (d)(8) of this section.

    (4) Calculation Method 4. If CEMS or a vent meter is not installed, 
you may calculate emissions using any standard simulation software 
package, such as AspenTech HYSYS[supreg], or API 4679 AMINECalc, that 
uses the Peng-Robinson equation of state and speciates CO<INF>2</INF> 
emissions. A minimum of the following, determined for typical operating 
conditions over the calendar year by engineering estimate and process 
knowledge based on best available data, must be used to characterize 
emissions:
    (i) Natural gas feed temperature, pressure, and flow rate.
    (ii) Acid gas content of feed natural gas.
    (iii) Acid gas content of outlet natural gas.
    (iv) Unit operating hours, excluding downtime for maintenance or 
standby.
    (v) Exit temperature of natural gas.
    (vi) Solvent pressure, temperature, circulation rate, and weight.
    (5) For Calculation Method 3, determine the gas flow rate of the 
inlet when using Equation W-4A of this section or the gas flow rate of 
the outlet when using Equation W-4B of this section for the natural gas 
stream of an AGR unit using a meter according to methods set forth in 
Sec.  98.234(b). If you do not have a continuous flow meter, either 
install a continuous flow meter or use an engineering calculation to 
determine the flow rate.
    (6) For Calculation Method 2, if a continuous gas analyzer is not 
available on the vent stack, either install a

[[Page 70388]]

continuous gas analyzer or take quarterly gas samples from the vent gas 
stream for each quarter that the AGR unit is operating to determine 
Vol<INF>CO2</INF> in Equation W-3 of this section, according to the 
methods set forth in Sec.  98.234(b).
    (7) For Calculation Method 3, if a continuous gas analyzer is 
installed on the inlet gas stream, then the continuous gas analyzer 
results must be used. If a continuous gas analyzer is not available, 
either install a continuous gas analyzer or take quarterly gas samples 
from the inlet gas stream for each quarter that the AGR unit is 
operating to determine Vol<INF>I</INF> in Equation W-4A or W-4B of this 
section, according to the methods set forth in Sec.  98.234(b).
    (8) For Calculation Method 3, determine annual average volumetric 
fraction of CO<INF>2</INF> content in natural gas flowing out of the 
AGR unit using one of the methods specified in paragraphs (d)(8)(i) 
through (d)(8)(iii) of this section.
    (i) If a continuous gas analyzer is installed on the outlet gas 
stream, then the continuous gas analyzer results must be used. If a 
continuous gas analyzer is not available, you may install a continuous 
gas analyzer.
    (ii) If a continuous gas analyzer is not available or installed, 
quarterly gas samples may be taken from the outlet gas stream for each 
quarter that the AGR unit is operating to determine Vol<INF>O</INF> in 
Equation W-4A or W-4B of this section, according to the methods set 
forth in Sec.  98.234(b).
    (iii) If a continuous gas analyzer is not available or installed, 
you may use sales line quality specification for CO<INF>2</INF> in 
natural gas.
    (9) Calculate annual volumetric CO<INF>2</INF> emissions at 
standard conditions using calculations in paragraph (t) of this 
section.
    (10) Calculate annual mass CO<INF>2</INF> emissions using 
calculations in paragraph (v) of this section.
    (11) Determine if CO<INF>2</INF> emissions from the AGR unit are 
recovered and transferred outside the facility. Adjust the 
CO<INF>2</INF> emissions estimated in paragraphs (d)(1) through (d)(10) 
of this section downward by the magnitude of CO<INF>2</INF> emissions 
recovered and transferred outside the facility.
    (e) Dehydrator vents. For dehydrator vents, calculate annual 
CH<INF>4</INF> and CO<INF>2</INF> emissions using the applicable 
calculation methods described in paragraphs (e)(1) through (e)(4) of 
this section. If emissions from dehydrator vents are routed to a vapor 
recovery system, you must adjust the emissions downward according to 
paragraph (e)(5) of this section. If emissions from dehydrator vents 
are routed to a flare or regenerator fire-box/fire tubes, you must 
calculate CH<INF>4</INF>, CO<INF>2</INF>, and N<INF>2</INF>O annual 
emissions as specified in paragraph (e)(6) of this section.
    (1) Calculation Method 1. Calculate annual mass emissions from 
glycol dehydrators that have an annual average of daily natural gas 
throughput that is greater than or equal to 0.4 million standard cubic 
feet per day by using a software program, such as AspenTech 
HYSYS[supreg] or GRI-GLYCalc\TM\, that uses the Peng-Robinson equation 
of state to calculate the equilibrium coefficient, speciates 
CH<INF>4</INF> and CO<INF>2</INF> emissions from dehydrators, and has 
provisions to include regenerator control devices, a separator flash 
tank, stripping gas and a gas injection pump or gas assist pump. The 
following parameters must be determined by engineering estimate based 
on best available data and must be used at a minimum to characterize 
emissions from dehydrators:
    (i) Feed natural gas flow rate.
    (ii) Feed natural gas water content.
    (iii) Outlet natural gas water content.
    (iv) Absorbent circulation pump type (e.g., natural gas pneumatic/
air pneumatic/electric).
    (v) Absorbent circulation rate.
    (vi) Absorbent type (e.g., triethylene glycol (TEG), diethylene 
glycol (DEG) or ethylene glycol (EG)).
    (vii) Use of stripping gas.
    (viii) Use of flash tank separator (and disposition of recovered 
gas).
    (ix) Hours operated.
    (x) Wet natural gas temperature and pressure.
    (xi) Wet natural gas composition. Determine this parameter using 
one of the methods described in paragraphs (e)(1)(xi)(A) through (D) of 
this section.
    (A) Use the GHG mole fraction as defined in paragraph (u)(2)(i) or 
(ii) of this section.
    (B) If the GHG mole fraction cannot be determined using paragraph 
(u)(2)(i) or (ii) of this section, select a representative analysis.
    (C) You may use an appropriate standard method published by a 
consensus-based standards organization if such a method exists or you 
may use an industry standard practice as specified in Sec.  98.234(b) 
to sample and analyze wet natural gas composition.
    (D) If only composition data for dry natural gas is available, 
assume the wet natural gas is saturated.
    (2) Calculation Method 2. Calculate annual volumetric emissions 
from glycol dehydrators that have an annual average of daily natural 
gas throughput that is less than 0.4 million standard cubic feet per 
day using Equation W-5 of this section:
[GRAPHIC] [TIFF OMITTED] TR25NO14.061


Where:

E<INF>s,i</INF> = Annual total volumetric GHG emissions (either 
CO<INF>2</INF> or CH<INF>4</INF>) at standard conditions in cubic 
feet.
EF<INF>i</INF> = Population emission factors for glycol dehydrators 
in thousand standard cubic feet per dehydrator per year. Use 73.4 
for CH<INF>4</INF> and 3.21 for CO<INF>2</INF> at 60[emsp14][deg]F 
and 14.7 psia.
Count = Total number of glycol dehydrators that have an annual 
average of daily natural gas throughput that is less than 0.4 
million standard cubic feet per day.
1000 = Conversion of EF<INF>i</INF> in thousand standard cubic feet 
to standard cubic feet.

    (3) Calculation Method 3. For dehydrators of any size that use 
desiccant, you must calculate emissions from the amount of gas vented 
from the vessel when it is depressurized for the desiccant refilling 
process using Equation W-6 of this section. Desiccant dehydrator 
emissions covered in this paragraph do not have to be calculated 
separately using the method specified in paragraph (i) of this section 
for blowdown vent stacks.
[GRAPHIC] [TIFF OMITTED] TR25NO14.028



[[Page 70389]]


Where:

E<INF>s,n</INF> = Annual natural gas emissions at standard 
conditions in cubic feet.
H = Height of the dehydrator vessel (ft).
D = Inside diameter of the vessel (ft).
P<INF>1</INF> = Atmospheric pressure (psia).
P<INF>2</INF> = Pressure of the gas (psia).
[pi] = pi (3.14).
%G = Percent of packed vessel volume that is gas.
N = Number of dehydrator openings in the calendar year.
100 = Conversion of %G to fraction.

    (4) For glycol dehydrators that use the calculation method in 
paragraph (e)(2) of this section, calculate both CH<INF>4</INF> and 
CO<INF>2</INF> mass emissions from volumetric GHG<INF>i</INF> emissions 
using calculations in paragraph (v) of this section. For desiccant 
dehydrators that use the calculation method in paragraph (e)(3) of this 
section, calculate both CH<INF>4</INF> and CO<INF>2</INF> volumetric 
and mass emissions from volumetric natural gas emissions using 
calculations in paragraphs (u) and (v) of this section.
    (5) Determine if the dehydrator unit has vapor recovery. Adjust the 
emissions estimated in paragraphs (e)(1), (2), and (3) of this section 
downward by the magnitude of emissions recovered using a vapor recovery 
system as determined by engineering estimate based on best available 
data.
    (6) Calculate annual emissions from dehydrator vents to flares or 
regenerator fire-box/fire tubes as follows:
    (i) Use the dehydrator vent volume and gas composition as 
determined in paragraphs (e)(1) through (5) of this section, as 
applicable.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this section to determine dehydrator vent emissions from the flare or 
regenerator combustion gas vent.
    (f) Well venting for liquids unloadings. Calculate annual 
volumetric natural gas emissions from well venting for liquids 
unloading using one of the calculation methods described in paragraphs 
(f)(1), (2), or (3) of this section. Calculate annual CH<INF>4</INF> 
and CO<INF>2</INF> volumetric and mass emissions using the method 
described in paragraph (f)(4) of this section.
    (1) Calculation Method 1. Calculate emissions from wells with 
plunger lifts and wells without plunger lifts separately. For at least 
one well of each unique well tubing diameter group and pressure group 
combination in each sub-basin category (see Sec.  98.238 for the 
definitions of tubing diameter group, pressure group, and sub-basin 
category), where gas wells are vented to the atmosphere to expel 
liquids accumulated in the tubing, install a recording flow meter 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 the total emissions 
from well venting to the atmosphere for liquids unloading using 
Equation W-7A of this section. For any tubing diameter group and 
pressure group combination in a sub-basin where liquids unloading 
occurs both with and without plunger lifts, Equation W-7A will be used 
twice, once for wells with plunger lifts and once for wells without 
plunger lifts.
[GRAPHIC] [TIFF OMITTED] TR25NO14.029


Where:

E<INF>a</INF> = Annual natural gas emissions for all wells of the 
same tubing diameter group and pressure group combination in a sub-
basin at actual conditions, a, in cubic feet. Calculate emission 
from wells with plunger lifts and wells without plunger lifts 
separately.
h = Total number of wells of the same tubing diameter group and 
pressure group combination in a sub-basin either with or without 
plunger lifts.
p = Wells 1 through h of the same tubing diameter group and pressure 
group combination in a sub-basin.
T<INF>p</INF> = Cumulative amount of time in hours of venting for 
each well, p, of the same tubing diameter group and pressure group 
combination in a sub-basin during the year. If the available venting 
data do not contain a record of the date of the venting events and 
data are not available to provide the venting hours for the specific 
time period of January 1 to December 31, you may calculate an 
annualized vent time, T<INF>p</INF>, using Equation W-7B of this 
section.
FR = Average flow rate in cubic feet per hour for all measured wells 
of the same tubing diameter group and pressure group combination in 
a sub-basin, over the duration of the liquids unloading, under 
actual conditions as determined in paragraph (f)(1)(i) of this 
section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.030


 Where:

HR<INF>p</INF> = Cumulative amount of time in hours of venting for 
each well, p, during the monitoring period.
MP<INF>p</INF> = Time period, in days, of the monitoring period for 
each well, p. A minimum of 300 days in a calendar year are required. 
The next period of data collection must start immediately following 
the end of data collection for the previous reporting year.
D<INF>p</INF> = Time period, in days during which the well, p, was 
in production (365 if the well was in production for the entire 
year).

    (i) Determine the well vent average flow rate (``FR'' in Equation 
W-7A of this section) as specified in paragraphs (f)(1)(i)(A) through 
(C) of this section for at least one well in a unique well tubing 
diameter group and pressure group combination in each sub-basin 
category. Calculate emissions from wells with plunger lifts and wells 
without plunger lifts separately.
    (A) Calculate the average flow rate per hour of venting for each 
unique tubing diameter group and pressure group combination in each 
sub-basin category by dividing the recorded total annual flow by the 
recorded time (in hours) for all measured liquid unloading events with 
venting to the atmosphere.
    (B) Apply the average hourly flow rate calculated under paragraph 
(f)(1)(i)(A) of this section to all wells in the same pressure group 
that have the same tubing diameter group, for the number of hours of 
venting these wells.
    (C) Calculate a new average flow rate every other calendar year 
starting with the first calendar year of data collection. For a new 
producing sub-basin category, calculate an average flow rate beginning 
in the first year of production.
    (ii) Calculate natural gas volumetric emissions at standard 
conditions using calculations in paragraph (t) of this section.
    (2) Calculation Method 2. Calculate the total emissions for each 
sub-basin from well venting to the atmosphere for liquids unloading 
without plunger lift assist using Equation W-8 of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.031



[[Page 70390]]


Where:

E<INF>s</INF> = Annual natural gas emissions for each sub-basin at 
standard conditions, s, in cubic feet per year.
W = Total number of wells with well venting for liquids unloading 
for each sub-basin.
p = Wells 1 through W with well venting for liquids unloading for 
each sub-basin.
V<INF>p</INF> = Total number of unloading events in the monitoring 
period per well, p.
0.37x10<SUP>-3</SUP> = {3.14 (pi)/4{time} /{14.7*144{time}  (psia 
converted to pounds per square feet).
CD<INF>p</INF> = Casing internal diameter for each well, p, in 
inches.
WD<INF>p</INF> = Well depth from either the top of the well or the 
lowest packer to the bottom of the well, for each well, p, in feet.
SP<INF>p</INF> = For each well, p, shut-in pressure or surface 
pressure for wells with tubing production, or casing pressure for 
each well with no packers, in pounds per square inch absolute 
(psia). If casing pressure is not available for each well, you may 
determine the casing pressure by multiplying the tubing pressure of 
each well with a ratio of casing pressure to tubing pressure from a 
well in the same sub-basin for which the casing pressure is known. 
The tubing pressure must be measured during gas flow to a flow-line. 
The shut-in pressure, surface pressure, or casing pressure must be 
determined just prior to liquids unloading when the well production 
is impeded by liquids loading or closed to the flow-line by surface 
valves.
SFR<INF>p</INF> = Average flow-line rate of gas for well, p, at 
standard conditions in cubic feet per hour. Use Equation W-33 of 
this section to calculate the average flow-line rate at standard 
conditions.
HR<INF>p,q</INF> = Hours that each well, p, was left open to the 
atmosphere during each unloading event, q.
1.0 = Hours for average well to blowdown casing volume at shut-in 
pressure.
q = Unloading event.
Z<INF>p,q</INF> = If HR<INF>p,q</INF> is less than 1.0 then 
Z<INF>p,q</INF> is equal to 0. If HR<INF>p,q</INF> is greater than 
or equal to 1.0 then Z<INF>p,q</INF> is equal to 1.

    (3) Calculation Method 3. Calculate the total emissions for each 
sub-basin from well venting to the atmosphere for liquids unloading 
with plunger lift assist using Equation W-9 of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.032


Where:

E<INF>s</INF> = Annual natural gas emissions for each sub-basin at 
standard conditions, s, in cubic feet per year.
W = Total number of wells with plunger lift assist and well venting 
for liquids unloading for each sub-basin.
p = Wells 1 through W with well venting for liquids unloading for 
each sub-basin.
V<INF>p</INF> = Total number of unloading events in the monitoring 
period for each well, p.
0.37x10<SUP>-3</SUP> = {3.14 (pi)/4{time} /{14.7*144{time}  (psia 
converted to pounds per square feet).
TD<INF>p</INF> = Tubing internal diameter for each well, p, in 
inches.
WD<INF>p</INF> = Tubing depth to plunger bumper for each well, p, in 
feet.
SP<INF>p</INF> = Flow-line pressure for each well, p, in pounds per 
square inch absolute (psia), using engineering estimate based on 
best available data.
SFR<INF>p</INF> = Average flow-line rate of gas for well, p, at 
standard conditions in cubic feet per hour. Use Equation W-33 of 
this section to calculate the average flow-line rate at standard 
conditions.
HR<INF>p,q</INF> = Hours that each well, p, was left open to the 
atmosphere during each unloading event, q.
0.5 = Hours for average well to blowdown tubing volume at flow-line 
pressure.
q = Unloading event.
Z<INF>p,q</INF> = If HR<INF>p,q</INF> is less than 0.5 then 
Z<INF>p,q</INF> is equal to 0. If HR<INF>p,q</INF> is greater than 
or equal to 0.5 then Z<INF>p,q</INF> is equal to 1.

    (4) Calculate CH<INF>4</INF> and CO<INF>2</INF> volumetric and mass 
emissions from volumetric natural gas emissions using calculations in 
paragraphs (u) and (v) of this section.
    (g) Gas well venting during completions and workovers with 
hydraulic fracturing. Calculate annual volumetric natural gas emissions 
from gas well venting during completions and workovers involving 
hydraulic fracturing using Equation W-10A or Equation W-10B of this 
section. Equation W-10A applies to well venting when the flowback rate 
is measured from a specified number of example completions or workovers 
and Equation W-10B applies when the flowback vent or flare volume is 
measured for each completion or workover. Completion and workover 
activities are separated into two periods, an initial period when 
flowback is routed to open pits or tanks and a subsequent period when 
gas content is sufficient to route the flowback to a separator or when 
the gas content is sufficient to allow measurement by the devices 
specified in paragraph (g)(1) of this section, regardless of whether a 
separator is actually utilized. If you elect to use Equation W-10A of 
this section, you must follow the procedures specified in paragraph 
(g)(1) of this section. Emissions must be calculated separately for 
completions and workovers, for each sub-basin, and for each well type 
combination identified in paragraph (g)(2) of this section. You must 
calculate CH<INF>4</INF> and CO<INF>2</INF> volumetric and mass 
emissions as specified in paragraph (g)(3) of this section. If 
emissions from gas well venting during completions and workovers with 
hydraulic fracturing are routed to a flare, you must calculate 
CH<INF>4</INF>, CO<INF>2</INF>, and N<INF>2</INF>O annual emissions as 
specified in paragraph (g)(4) of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.033


Where:

E<INF>s,n</INF> = Annual volumetric natural gas emissions in 
standard cubic feet from gas well venting during completions or 
workovers following hydraulic fracturing for each sub-basin and well 
type combination.
W = Total number of wells completed or worked over using hydraulic 
fracturing in a sub-basin and well type combination.
T<INF>p,s</INF> = Cumulative amount of time of flowback, after 
sufficient quantities of gas are present to enable separation, where 
gas vented or flared for the completion or workover, in hours, for 
each well, p, in a sub-basin and well type combination during the 
reporting year. This may include non-contiguous periods of venting 
or flaring.

[[Page 70391]]

T<INF>p,i</INF> = Cumulative amount of time of flowback to open 
tanks/pits, from when gas is first detected until sufficient 
quantities of gas are present to enable separation, for the 
completion or workover, in hours, for each well, p, in a sub-basin 
and well type combination during the reporting year. This may 
include non-contiguous periods of routing to open tanks/pits.
FRM<INF>s</INF> = Ratio of average flowback, during the period when 
sufficient quantities of gas are present to enable separation, of 
well completions and workovers from hydraulic fracturing to 30-day 
production rate for the sub-basin and well type combination, 
calculated using procedures specified in paragraph (g)(1)(iii) of 
this section, expressed in standard cubic feet per hour.
FRM<INF>i</INF> = Ratio of initial flowback rate during well 
completions and workovers from hydraulic fracturing to 30-day 
production rate for the sub-basin and well type combination, 
calculated using procedures specified in paragraph (g)(1)(iv) of 
this section, expressed in standard cubic feet per hour, for the 
period of flow to open tanks/pits.
PR<INF>s,p</INF> = Average production flow rate during the first 30 
days of production after completions of newly drilled gas wells or 
gas well workovers using hydraulic fracturing in standard cubic feet 
per hour of each well p, that was measured in the sub-basin and well 
type combination.
EnF<INF>s,p</INF> = Volume of N<INF>2</INF> injected gas in cubic 
feet at standard conditions that was injected into the reservoir 
during an energized fracture job for each well, p, as determined by 
using an appropriate meter according to methods described in Sec.  
98.234(b), or by using receipts of gas purchases that are used for 
the energized fracture job. Convert to standard conditions using 
paragraph (t) of this section. If the fracture process did not 
inject gas into the reservoir or if the injected gas is 
CO<INF>2</INF> then EnF<INF>s,p</INF> is 0.
FV<INF>s,p</INF> = Flow volume vented or flared of each well, p, in 
standard cubic feet measured using a recording flow meter (digital 
or analog) on the vent line to measure flowback during the 
separation period of the completion or workover according to methods 
set forth in Sec.  98.234(b).
FR<INF>p,i</INF> = Flow rate vented or flared of each well, p, in 
standard cubic feet per hour measured using a recording flow meter 
(digital or analog) on the vent line to measure the flowback, at the 
beginning of the period of time when sufficient quantities of gas 
are present to enable separation, of the completion or workover 
according to methods set forth in Sec.  98.234(b).

    (1) If you elect to use Equation W-10A of this section, you must 
use Calculation Method 1 as specified in paragraph (g)(1)(i) of this 
section, or Calculation Method 2 as specified in paragraph (g)(1)(ii) 
of this section, to determine the value of FRM<INF>s</INF> and 
FRM<INF>i</INF>. These values must be based on the flow rate for 
flowback, once sufficient gas is present to enable separation. The 
number of measurements or calculations required to estimate 
FRM<INF>s</INF> and FRM<INF>i</INF> must be determined individually for 
completions and workovers per sub-basin and well type combination as 
follows: Complete measurements or calculations for at least one 
completion or workover for less than or equal to 25 completions or 
workovers for each well type combination within a sub-basin; complete 
measurements or calculations for at least two completions or workovers 
for 26 to 50 completions or workovers for each sub-basin and well type 
combination; complete measurements or calculations for at least three 
completions or workovers for 51 to 100 completions or workovers for 
each sub-basin and well type combination; complete measurements or 
calculations for at least four completions or workovers for 101 to 250 
completions or workovers for each sub-basin and well type combination; 
and complete measurements or calculations for at least five completions 
or workovers for greater than 250 completions or workovers for each 
sub-basin and well type combination.
    (i) Calculation Method 1. You must use Equation W-12A as specified 
in paragraph (g)(1)(iii) of this section to determine the value of 
FRM<INF>s</INF>. You must use Equation W-12B as specified in paragraph 
(g)(1)(iv) of this section to determine the value of FRM<INF>i</INF>. 
The procedures specified in paragraphs (g)(1)(v) and (vi) also apply. 
When making flowback measurements for use in Equations W-12A and W-12B 
of this section, you must use a recording flow meter (digital or 
analog) installed on the vent line, ahead of a flare or vent, to 
measure the flowback rates in units of standard cubic feet per hour 
according to methods set forth in Sec.  98.234(b).
    (ii) Calculation Method 2. You must use Equation W-12A as specified 
in paragraph (g)(1)(iii) of this section to determine the value of 
FRM<INF>s</INF>. You must use Equation W-12B as specified in paragraph 
(g)(1)(iv) of this section to determine the value of FRM<INF>i</INF>. 
The procedures specified in paragraphs (g)(1)(v) and (vi) also apply. 
When calculating the flowback rates for use in Equations W-12A and W-
12B of this section based on well parameters, you must record the well 
flowing pressure immediately upstream (and immediately downstream in 
subsonic flow) of a well choke according to methods set forth in Sec.  
98.234(b) to calculate the well flowback. The upstream pressure must be 
surface pressure and reservoir pressure cannot be assumed. The 
downstream pressure must be measured after the choke and atmospheric 
pressure cannot be assumed. Calculate flowback rate using Equation W-
11A of this section for subsonic flow or Equation W-11B of this section 
for sonic flow. You must use best engineering estimates based on best 
available data along with Equation W-11C of this section to determine 
whether the predominant flow is sonic or subsonic. If the value of R in 
Equation W-11C of this section is greater than or equal to 2, then flow 
is sonic; otherwise, flow is subsonic. Convert calculated 
FR<INF>a</INF> values from actual conditions upstream of the 
restriction orifice to standard conditions (FR<INF>s,p</INF> and 
FR<INF>i,p</INF>) for use in Equations W-12A and W-12B of this section 
using Equation W-33 in paragraph (t) of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.034

Where:

FR<INF>a</INF> = Flowback rate in actual cubic feet per hour, under 
actual subsonic flow conditions.
A = Cross sectional open area of the restriction orifice (m\2\).
P<INF>1</INF> = Pressure immediately upstream of the choke (psia).
T<INF>u</INF> = Temperature immediately upstream of the choke 
(degrees Kelvin).
P<INF>2</INF> = Pressure immediately downstream of the choke (psia).
3430 = Constant with units of m\2\/(sec \2\ * K).
1.27*10\5\ = Conversion from m\3\/second to ft\3\/hour.

[[Page 70392]]

[GRAPHIC] [TIFF OMITTED] TR25NO14.035

Where:

FR<INF>a</INF> = Flowback rate in actual cubic feet per hour, under 
actual sonic flow conditions.
A = Cross sectional open area of the restriction orifice (m\2\).
T<INF>u</INF> = Temperature immediately upstream of the choke 
(degrees Kelvin).
187.08 = Constant with units of m\2\/(sec\2\ * K).
1.27*10 \5\ = Conversion from m \3\/second to ft\3\/hour.

[GRAPHIC] [TIFF OMITTED] TR25NO14.036

Where:

R = Pressure ratio.
P<INF>1</INF> = Pressure immediately upstream of the choke (psia).
P<INF>2</INF> = Pressure immediately downstream of the choke (psia).


    (iii) For Equation W-10A of this section, calculate FRM<INF>s</INF> 
using Equation W-12A of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.037

Where:

FRM<INF>s</INF> = Ratio of average flowback rate, during the period 
of time when sufficient quantities of gas are present to enable 
separation, of well completions and workovers from hydraulic 
fracturing to 30-day production rate for each sub-basin and well 
type combination.
FR<INF>s,p</INF> = Measured average flowback rate from Calculation 
Method 1 described in paragraph (g)(1)(i) of this section or 
calculated average flowback rate from Calculation Method 2 described 
in paragraph (g)(1)(ii) of this section, during the separation 
period in standard cubic feet per hour for well(s) p for each sub-
basin and well type combination. Convert measured and calculated 
FR<INF>a</INF> values from actual conditions upstream of the 
restriction orifice (FR<INF>a</INF>) to standard conditions 
(FR<INF>s,p</INF>) for each well p using Equation W-33 in paragraph 
(t) of this section. You may not use flow volume as used in Equation 
W-10B converted to a flow rate for this parameter.
PR<INF>s,p</INF> = Average production flow rate during the first 30 
days of production after completions of newly drilled gas wells or 
gas well workovers using hydraulic fracturing, in standard cubic 
feet per hour for each well, p, that was measured in the sub-basin 
and well type combination.
N = Number of measured or calculated well completions or workovers 
using hydraulic fracturing in a sub-basin and well type combination.

    (iv) For Equation W-10A of this section, calculate FRM<INF>i</INF> 
using Equation W-12B of this section.

[GRAPHIC] [TIFF OMITTED] TR25NO14.038

Where:

FRM<INF>i</INF> = Ratio of flowback gas rate while flowing to open 
tanks/pits during well completions and workovers from hydraulic 
fracturing to 30-day production rate.
FR<INF>i,p</INF> = Initial measured gas flowback rate from 
Calculation Method 1 described in paragraph (g)(1)(i) of this 
section or initial calculated flow rate from Calculation Method 2 
described in paragraph (g)(1)(ii) of this section in standard cubic 
feet per hour for well(s), p, for each sub-basin and well type 
combination. Measured and calculated FR<INF>i,p</INF> values must be 
based on flow conditions at the beginning of the separation period 
and must be expressed at standard conditions.
PR<INF>s,p</INF> = Average production flow rate during the first 30-
days of production after completions of newly drilled gas wells or 
gas well workovers using hydraulic fracturing, in standard cubic 
feet per hour of each well, p, that was measured in the sub-basin 
and well type combination.
N = Number of measured or calculated well completions or workovers 
using hydraulic fracturing in a sub-basin and well type combination.

    (v) For Equation W-10A of this section, the ratio of flowback rate 
during well completions and workovers from hydraulic fracturing to 30-
day production rate 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 flowback and for the first 
30 day average production rate for each of these wells.
    (vi) For Equation W-12A and W-12B of this section, calculate new 
flowback rates for horizontal and vertical gas well completions and 
horizontal and vertical gas well workovers in each sub-basin category 
once every two years starting in the first calendar year of data 
collection.
    (2) For paragraphs (g) introductory text and (g)(1) of this 
section, measurements and calculations are completed separately for 
workovers and completions per sub-basin and well type combination. A 
well type combination is a unique combination of the parameters listed 
in paragraphs (g)(2)(i) through (iii) of this section.
    (i) Vertical or horizontal (directional drilling).
    (ii) With flaring or without flaring.
    (iii) Reduced emission completion/workover or not reduced emission 
completion/workover.
    (3) Calculate both CH<INF>4</INF> and CO<INF>2</INF> volumetric and 
mass emissions from total natural gas volumetric emissions using 
calculations in paragraphs (u) and (v) of this section.
    (4) Calculate annual emissions from gas well venting during well 
completions and workovers from hydraulic fracturing where all or a 
portion of the gas is flared as specified in paragraphs (g)(4)(i) and 
(ii) of this section.
    (i) Use the volumetric total natural gas emissions vented to the 
atmosphere during well completions and workovers as determined in 
paragraph (g) of this section to calculate volumetric and mass 
emissions using paragraphs (u) and (v) of this section.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this section to adjust emissions for the portion of gas flared during 
well completions and workovers using hydraulic fracturing. This 
adjustment to emissions from completions using flaring, versus 
completions without flaring, accounts for the conversion of 
CH<INF>4</INF> to CO<INF>2</INF> in the flare and for the formation on 
N<INF>2</INF>O during flaring.
    (h) Gas well venting during completions and workovers without 
hydraulic fracturing. Calculate annual volumetric natural gas emissions 
from each gas well venting during workovers without hydraulic 
fracturing using Equation W-13A of this section. Calculate annual 
volumetric natural gas emissions from each gas well venting during 
completions without hydraulic fracturing using Equation W-13B of this 
section. You must convert annual volumetric natural gas emissions to 
CH<INF>4</INF> and CO<INF>2</INF> volumetric and mass emissions as 
specified in paragraph (h)(1) of this section. If emissions from gas 
well venting during completions and workovers without hydraulic 
fracturing are routed to a flare, you must calculate CH<INF>4</INF>, 
CO<INF>2</INF>, and N<INF>2</INF>O annual emissions as specified in 
paragraph (h)(2) of this section.

[[Page 70393]]

[GRAPHIC] [TIFF OMITTED] TR25NO14.039

Where:

E<INF>s,wo</INF> = Annual volumetric natural gas emissions in 
standard cubic feet from gas well venting during well workovers 
without hydraulic fracturing.
N<INF>wo</INF> = Number of workovers per sub-basin category that do 
not involve hydraulic fracturing in the reporting year.
EF<INF>wo</INF> = Emission factor for non-hydraulic fracture well 
workover venting in standard cubic feet per workover. Use 3,114 
standard cubic feet natural gas per well workover without hydraulic 
fracturing.
E<INF>s,p</INF> = Annual volumetric natural gas emissions in 
standard cubic feet from gas well venting during well completions 
without hydraulic fracturing.
p = Well completions 1 through f in a sub-basin.
f = Total number of well completions without hydraulic fracturing in 
a sub-basin category.
V<INF>p</INF> = Average daily gas production rate in standard cubic 
feet per hour for each well, p, undergoing completion without 
hydraulic fracturing. This is the total annual gas production volume 
divided by total number of hours the wells produced to the flow-
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.
T<INF>p</INF> = Time that gas is vented to either the atmosphere or 
a flare for each well, p, undergoing completion without hydraulic 
fracturing, in hours during the year.

    (1) Calculate both CH<INF>4</INF> and CO<INF>2</INF> volumetric 
emissions from natural gas volumetric emissions using calculations in 
paragraph (u) of this section. Calculate both CH<INF>4</INF> and 
CO<INF>2</INF> mass emissions from volumetric emissions vented to 
atmosphere using calculations in paragraph (v) of this section.
    (2) Calculate annual emissions of CH<INF>4</INF>, CO<INF>2</INF>, 
and N<INF>2</INF>O from gas well venting to flares during well 
completions and workovers not involving hydraulic fracturing as 
specified in paragraphs (h)(2)(i) and (ii) of this section.
    (i) Use the gas well venting volume and gas composition during well 
completions and workovers that are flared as determined using the 
methods specified in paragraphs (h) and (h)(1) of this section.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this section to determine emissions from the flare for gas well venting 
to a flare during completions and workovers without hydraulic 
fracturing.
    (i) Blowdown vent stacks. Calculate CO<INF>2</INF> and 
CH<INF>4</INF> blowdown vent stack emissions from the depressurization 
of equipment to reduce system pressure for planned or emergency 
shutdowns resulting from human intervention or to take equipment out of 
service for maintenance as specified in either paragraph (i)(2) or (3) 
of this section. You may use the method in paragraph (i)(2) of this 
section for some blowdown vent stacks at your facility and the method 
in paragraph (i)(3) of this section for other blowdown vent stacks at 
your facility. Equipment with a unique physical volume of less than 50 
cubic feet as determined in paragraph (i)(1) of this section are not 
subject to the requirements in paragraphs (i)(2) through (4) of this 
section. The requirements in this paragraph (i) do not apply to 
blowdown vent stack emissions from depressurizing to a flare, over-
pressure relief, operating pressure control venting, blowdown of non-
GHG gases, and desiccant dehydrator blowdown venting before reloading.
    (1) Method for calculating unique physical volumes. You must 
calculate each unique physical volume (including pipelines, compressor 
case or cylinders, manifolds, suction bottles, discharge bottles, and 
vessels) between isolation valves, in cubic feet, by using engineering 
estimates based on best available data.
    (2) Method for determining emissions from blowdown vent stacks 
according to equipment or event type. If you elect to determine 
emissions according to each equipment or event type, using unique 
physical volumes as calculated in paragraph (i)(1) of this section, you 
must calculate emissions as specified in paragraph (i)(2)(i) of this 
section and either paragraph (i)(2)(ii) or, if applicable, paragraph 
(i)(2)(iii) of this section for each equipment or event type. Equipment 
or event types must be grouped into the following seven categories: 
Facility piping (i.e., piping within the facility boundary other than 
physical volumes associated with distribution pipelines), pipeline 
venting (i.e., physical volumes associated with distribution pipelines 
vented within the facility boundary), compressors, scrubbers/strainers, 
pig launchers and receivers, emergency shutdowns (this category 
includes emergency shutdown blowdown emissions regardless of equipment 
type), and all other equipment with a physical volume greater than or 
equal to 50 cubic feet. If a blowdown event resulted in emissions from 
multiple equipment types and the emissions cannot be apportioned to the 
different equipment types, then categorize the blowdown event as the 
equipment type that represented the largest portion of the emissions 
for the blowdown event.
    (i) Calculate the total annual natural gas emissions from each 
unique physical volume that is blown down using either Equation W-14A 
or W-14B of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.040


Where:

E<INF>s,n</INF> = Annual natural gas emissions at standard 
conditions from each unique physical volume that is blown down, in 
cubic feet.
N = Number of occurrences of blowdowns for each unique physical 
volume in the calendar year.
V = Unique physical volume between isolation valves, in cubic feet, 
as calculated in paragraph (i)(1) of this section.
C = Purge factor is 1 if the unique physical volume is not purged, 
or 0 if the unique physical volume is purged using non-GHG gases.

[[Page 70394]]

T<INF>s</INF> = Temperature at standard conditions 
(60[emsp14][deg]F).
T<INF>a</INF> = Temperature at actual conditions in the unique 
physical volume ([deg]F).
P<INF>s</INF> = Absolute pressure at standard conditions (14.7 
psia).
P<INF>a</INF> = Absolute pressure at actual conditions in the unique 
physical volume (psia).
Z<INF>a</INF> = Compressibility factor at actual conditions for 
natural gas. You may use either a default compressibility factor of 
1, or a site-specific compressibility factor based on actual 
temperature and pressure conditions.

[GRAPHIC] [TIFF OMITTED] TR25NO14.041


Where:

E<INF>s,n</INF> = Annual natural gas emissions at standard 
conditions from each unique physical volume that is blown down, in 
cubic feet.
p = Individual occurrence of blowdown for the same unique physical 
volume.
N = Number of occurrences of blowdowns for each unique physical 
volume in the calendar year.
V<INF>p</INF> = Unique physical volume between isolation valves, in 
cubic feet, for each blowdown ``p.''
T<INF>s</INF> = Temperature at standard conditions 
(60[emsp14][deg]F).
T<INF>a,p</INF> = Temperature at actual conditions in the unique 
physical volume ([deg]F) for each blowdown ``p''.
P<INF>s</INF> = Absolute pressure at standard conditions (14.7 
psia).
P<INF>a,b,p</INF> = Absolute pressure at actual conditions in the 
unique physical volume (psia) at the beginning of the blowdown 
``p''.
P<INF>a,e,p</INF> = Absolute pressure at actual conditions in the 
unique physical volume (psia) at the end of the blowdown ``p''; 0 if 
blowdown volume is purged using non-GHG gases.
Z<INF>a</INF> = Compressibility factor at actual conditions for 
natural gas. You may use either a default compressibility factor of 
1, or a site-specific compressibility factor based on actual 
temperature and pressure conditions.

    (ii) Except as allowed in paragraph (i)(2)(iii) of this section, 
calculate annual CH<INF>4</INF> and CO<INF>2</INF> volumetric and mass 
emissions from each unique physical volume that is blown down by using 
the annual natural gas emission value as calculated in either Equation 
W-14A or Equation W-14B of paragraph (i)(2)(i) of this section and the 
calculation method specified in paragraph (i)(4) of this section. 
Calculate the total annual CH<INF>4</INF> and CO<INF>2</INF> emissions 
for each equipment or event type by summing the annual CH<INF>4</INF> 
and CO<INF>2</INF> mass emissions for all unique physical volumes 
associated with the equipment or event type.
    (iii) For onshore natural gas transmission compression facilities 
and LNG import and export equipment, as an alternative to using the 
procedures in paragraph (i)(2)(ii) of this section, you may elect to 
sum the annual natural gas emissions as calculated using either 
Equation W-14A or Equation W-14B of paragraph (i)(2)(i) of this section 
for all unique physical volumes associated with the equipment type or 
event type. Calculate the total annual CH<INF>4</INF> and 
CO<INF>2</INF> volumetric and mass emissions for each equipment type or 
event type using the sums of the total annual natural gas emissions for 
each equipment type and the calculation method specified in paragraph 
(i)(4) of this section.
    (3) Method for determining emissions from blowdown vent stacks 
using a flow meter. In lieu of determining emissions from blowdown vent 
stacks as specified in paragraph (i)(2) of this section, you may use a 
flow meter and measure blowdown vent stack emissions for any unique 
physical volumes determined according to paragraph (i)(1) of this 
section to be greater than or equal to 50 cubic feet. If you choose to 
use this method, you must measure the natural gas emissions from the 
blowdown(s) through the monitored stack(s) using a flow meter according 
to methods in Sec.  98.234(b), and calculate annual CH<INF>4</INF> and 
CO<INF>2</INF> volumetric and mass emissions measured by the meters 
according to paragraph (i)(4) of this section.
    (4) Method for converting from natural gas emissions to GHG 
volumetric and mass emissions. Calculate both CH<INF>4</INF> and 
CO<INF>2</INF> volumetric and mass emissions using the methods 
specified in paragraphs (u) and (v) of this section.
    (j) Onshore production storage tanks. Calculate CH<INF>4</INF>, 
CO<INF>2</INF>, and N<INF>2</INF>O (when flared) emissions from 
atmospheric pressure fixed roof storage tanks receiving hydrocarbon 
produced liquids from onshore petroleum and natural gas production 
facilities (including stationary liquid storage not owned or operated 
by the reporter), as specified in this paragraph (j). For wells flowing 
to gas-liquid separators with annual average daily throughput of oil 
greater than or equal to 10 barrels per day, calculate annual 
CH<INF>4</INF> and CO<INF>2</INF> using Calculation Method 1 or 2 as 
specified in paragraphs (j)(1) and (2) of this section. For wells 
flowing directly to atmospheric storage tanks without passing through a 
wellhead separator with throughput greater than or equal to 10 barrels 
per day, calculate annual CH<INF>4</INF> and CO<INF>2</INF> emissions 
using Calculation Method 2 as specified in paragraph (j)(2) of this 
section. For wells flowing to gas-liquid separators or directly to 
atmospheric storage tanks with throughput less than 10 barrels per day, 
use Calculation Method 3 as specified in paragraph (j)(3) of this 
section. If you use Calculation Method 1 or Calculation Method 2, you 
must also calculate emissions that may have occurred due to dump valves 
not closing properly using the method specified in paragraph (j)(6) of 
this section. If emissions from atmospheric pressure fixed roof storage 
tanks are routed to a vapor recovery system, you must adjust the 
emissions downward according to paragraph (j)(4) of this section. If 
emissions from atmospheric pressure fixed roof storage tanks are routed 
to a flare, you must calculate CH<INF>4</INF>, CO<INF>2</INF>, and 
N<INF>2</INF>O annual emissions as specified in paragraph (j)(5) of 
this section.
    (1) Calculation Method 1. Calculate annual CH<INF>4</INF> and 
CO<INF>2</INF> emissions from onshore production storage tanks using 
operating conditions in the last wellhead gas-liquid separator before 
liquid transfer to storage tanks. Calculate flashing emissions with a 
software program, such as AspenTech HYSYS[supreg] or API 4697 E&P Tank, 
that uses the Peng-Robinson equation of state, models flashing 
emissions, and speciates CH<INF>4</INF> and CO<INF>2</INF> emissions 
that will result when the oil from the separator enters an atmospheric 
pressure storage tank. The following parameters must be determined for 
typical operating conditions over the year by engineering estimate and 
process knowledge based on best available data, and must be used at a 
minimum to characterize emissions from liquid transferred to tanks:
* * * * *
    (vii) Separator oil composition and Reid vapor pressure. If this 
data is not available, determine these parameters by using one of the 
methods described

[[Page 70395]]

in paragraphs (j)(1)(vii)(A) through (C) of this section.
* * * * *
    (2) Calculation Method 2. Calculate annual CH<INF>4</INF> and 
CO<INF>2</INF> emissions using the methods in paragraph (j)(2)(i) of 
this section for wells flowing to gas-liquid separators with annual 
average daily throughput of oil greater than or equal to 10 barrels per 
day. Calculate annual CH<INF>4</INF> and CO<INF>2</INF> emissions using 
the methods in paragraph (j)(2)(ii) of this section for wells with 
annual average daily oil production greater than or equal to 10 barrels 
per day that flow directly to atmospheric storage tanks.
    (i) Flow to storage tank after passing through a separator. Assume 
that all of the CH<INF>4</INF> and CO<INF>2</INF> in solution at 
separator temperature and pressure is emitted from oil sent to storage 
tanks. You may use an appropriate standard method published by a 
consensus-based standards organization if such a method exists or you 
may use an industry standard practice as described in Sec.  98.234(b) 
to sample and analyze separator oil composition at separator pressure 
and temperature.
    (ii) Flow to storage tank direct from wells. Calculate 
CH<INF>4</INF> and CO<INF>2</INF> emissions using either of the methods 
in paragraph (j)(2)(ii)(A) or (B) of this section.
    (A) 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 CH<INF>4</INF> and CO<INF>2</INF> in 
both oil and gas are emitted from the tank.
    (B) If well production oil and gas compositions are not available, 
use default oil and gas compositions in software programs, such as API 
4697 E&P Tank, that most closely match your well production gas/oil 
ratio and API gravity and assume all of the CH<INF>4</INF> and 
CO<INF>2</INF> in both oil and gas are emitted from the tank.
    (3) Calculation Method 3. Calculate CH<INF>4</INF> and 
CO<INF>2</INF> emissions using Equation W-15 of this section:
[GRAPHIC] [TIFF OMITTED] TR25NO14.062

Where:

E<INF>s,i</INF> = Annual total volumetric GHG emissions (either 
CO<INF>2</INF> or CH<INF>4</INF>) at standard conditions in cubic 
feet.
EF<INF>i</INF> = Population emission factor for separators or wells 
in thousand standard cubic feet per separator or well per year, for 
crude oil use 4.2 for CH<INF>4</INF> and 2.8 for CO<INF>2</INF> at 
60[emsp14][deg]F and 14.7 psia, and for gas condensate use 17.6 for 
CH<INF>4</INF> and 2.8 for CO<INF>2</INF> at 60[emsp14][deg]F and 
14.7 psia.
Count = Total number of separators or wells with annual average 
daily throughput less than 10 barrels per day. Count only separators 
or wells that feed oil directly to the storage tank.
1,000 = Conversion from thousand standard cubic feet to standard 
cubic feet.

    (4) Determine if the storage tank receiving your separator oil has 
a vapor recovery system.
    (i) Adjust the emissions estimated in paragraphs (j)(1) through (3) 
of this section downward by the magnitude of emissions recovered using 
a vapor recovery system as determined by engineering estimate based on 
best available data.
    (ii) [Reserved]
    (5) Determine if the storage tank receiving your separator oil is 
sent to flare(s).
    (i) Use your separator flash gas volume and gas composition as 
determined in this section.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this section to determine storage tank emissions from the flare.
    (6) If you use Calculation Method 1 or Calculation Method 2 in 
paragraph (j)(1) or (2) of this section, calculate emissions from 
occurrences of well pad gas-liquid separator liquid dump valves not 
closing during the calendar year by using Equation W-16 of this 
section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.042

Where:

E<INF>s,i,o</INF> = Annual volumetric GHG emissions at standard 
conditions from each storage tank in cubic feet that resulted from 
the dump valve on the gas-liquid separator not closing properly.
E<INF>n</INF> = Storage tank emissions as determined in paragraphs 
(j)(1), (j)(2) and, if applicable, (j)(4) of this section in 
standard cubic feet per year.
T<INF>n</INF> = Total time a dump valve is not closing properly in 
the calendar year in hours. Estimate T<INF>n</INF> based on 
maintenance, operations, or routine well pad inspections that 
indicate the period of time when the valve was malfunctioning in 
open or partially open position.
CF<INF>n</INF> = Correction factor for tank emissions for time 
period T<INF>n</INF> is 2.87 for crude oil production. Correction 
factor for tank emissions for time period T<INF>n</INF> is 4.37 for 
gas condensate production.
8,760 = Conversion to hourly emissions.

    (7) Calculate both CH<INF>4</INF> and CO<INF>2</INF> mass emissions 
from natural gas volumetric emissions using calculations in paragraph 
(v) of this section.
    (k) Transmission storage tanks. For vent stacks connected to one or 
more transmission condensate storage tanks, either water or 
hydrocarbon, without vapor recovery, in onshore natural gas 
transmission compression, calculate CH<INF>4</INF> and CO<INF>2</INF> 
annual emissions from compressor scrubber dump valve leakage as 
specified in paragraphs (k)(1) through (k)(4) of this section. If 
emissions from compressor scrubber dump valve leakage are routed to a 
flare, you must calculate CH<INF>4</INF>, CO<INF>2</INF>, and 
N<INF>2</INF>O annual emissions as specified in paragraph (k)(5) of 
this section.
    (1) Except as specified in paragraph (k)(1)(iv) of this section, 
you must monitor the tank vapor vent stack annually for emissions using 
one of the methods specified in paragraphs (k)(1)(i) through (iii) of 
this section.
    (i) Use an optical gas imaging instrument according to methods set 
forth in Sec.  98.234(a)(1).
    (ii) Measure the tank vent directly using a flow meter or high 
volume sampler according to methods in Sec.  98.234(b) or (d) for a 
duration of 5 minutes.
    (iii) Measure the tank vent using a calibrated bag according to 
methods in Sec.  98.234(c) for a duration of 5 minutes or until the bag 
is full, whichever is shorter.
    (iv) 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) If the tank vapors from the vent stack are continuous for 5 
minutes, or

[[Page 70396]]

the optical gas imaging instrument or acoustic leak detection device 
detects a leak, then you must use one of the methods in either 
paragraph (k)(2)(i) or (ii) of this section.
    (i) Use a flow meter, such as a turbine meter, calibrated bag, or 
high volume sampler to estimate tank vapor volumes from the vent stack 
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 (k)(1)(ii) or (iii) 
of this section to detect continuous leakage, this serves as the 
measurement.
    (ii) Use an acoustic leak detection device on each scrubber dump 
valve connected to the tank according to the method set forth in Sec.  
98.234(a)(5).
    (3) If a leaking dump valve is identified, the leak must be counted 
as having occurred since the beginning of the calendar year, or from 
the previous test that did not detect leaking in the same calendar 
year. If the leaking dump valve is fixed following leak detection, the 
leak duration will end upon being repaired. If a leaking dump valve is 
identified and not repaired, the leak must be counted as having 
occurred through the rest of the calendar year.
    (4) Use the requirements specified in paragraphs (k)(4)(i) and (ii) 
of this section to quantify annual emissions.
    (i) Use the appropriate gas composition in paragraph (u)(2)(iii) of 
this section.
    (ii) Calculate CH<INF>4</INF> and CO<INF>2</INF> volumetric and 
mass emissions at standard conditions using calculations in paragraphs 
(t), (u), and (v) of this section, as applicable to the monitoring 
equipment used.
    (5) Calculate annual emissions from storage tanks to flares as 
specified in paragraphs (k)(5)(i) and (ii) of this section.
    (i) Use the storage tank emissions volume and gas composition as 
determined in paragraphs (k)(1) through (4) of this section.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this section to determine storage tank emissions sent to a flare.
    (l) Well testing venting and flaring. Calculate CH<INF>4</INF> and 
CO<INF>2</INF> annual emissions from well testing venting as specified 
in paragraphs (l)(1) through (5) of this section. If emissions from 
well testing venting are routed to a flare, you must calculate 
CH<INF>4</INF>, CO<INF>2</INF>, and N<INF>2</INF>O annual emissions as 
specified in paragraph (l)(6) of this section.
    (1) Determine the gas to oil ratio (GOR) of the hydrocarbon 
production from oil well(s) tested. Determine the production rate from 
gas well(s) tested.
    (2) If GOR cannot be determined from your available data, then you 
must measure quantities reported in this section according to one of 
the procedures specified in paragraph (l)(2)(i) or (ii) of this section 
to determine GOR.
    (i) You may use an appropriate standard method published by a 
consensus-based standards organization if such a method exists.
    (ii) You may use an industry standard practice as described in 
Sec.  98.234(b).
    (3) Estimate venting emissions using Equation W-17A (for oil wells) 
or Equation W-17B (for gas wells) of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.063

Where:

E<INF>a,n</INF> = Annual volumetric natural gas emissions from 
well(s) testing in cubic feet under actual conditions.
GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil 
here refers to hydrocarbon liquids produced of all API gravities.
FR = Average annual flow rate in barrels of oil per day for the oil 
well(s) being tested.
PR = Average annual production rate in actual cubic feet per day for 
the gas well(s) being tested.
D = Number of days during the calendar year that the well(s) is 
tested.

    (4) Calculate natural gas volumetric emissions at standard 
conditions using calculations in paragraph (t) of this section.
    (5) Calculate both CH<INF>4</INF> and CO<INF>2</INF> volumetric and 
mass emissions from natural gas volumetric emissions using calculations 
in paragraphs (u) and (v) of this section.
    (6) Calculate emissions from well testing if emissions are routed 
to a flare as specified in paragraphs (l)(6)(i) and (ii) of this 
section.
    (i) Use the well testing emissions volume and gas composition as 
determined in paragraphs (l)(1) through (4) of this section.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this section to determine well testing emissions from the flare.
    (m) Associated gas venting and flaring. Calculate CH<INF>4</INF> 
and CO<INF>2</INF> annual emissions from associated gas venting not in 
conjunction with well testing (refer to paragraph (l): Well testing 
venting and flaring of this section) as specified in paragraphs (m)(1) 
through (4) of this section. If emissions from associated gas venting 
are routed to a flare, you must calculate CH<INF>4</INF>, 
CO<INF>2</INF>, and N<INF>2</INF>O annual emissions as specified in 
paragraph (m)(5) of this section.
    (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, use the GOR from a cluster of wells in the same sub-
basin category.
    (2) If GOR cannot be determined from your available data, then you 
must use one of the procedures specified in paragraphs (m)(2)(i) or 
(ii) of this section to determine GOR.
    (i) You may use an appropriate standard method published by a 
consensus-based standards organization if such a method exists.
    (ii) You may use an industry standard practice as described in 
Sec.  98.234(b).
    (3) Estimate venting emissions using Equation W-18 of this section.
    [GRAPHIC] [TIFF OMITTED] TR25NO14.043
    

[[Page 70397]]


Where:

E<INF>s,n</INF> = Annual volumetric natural gas emissions, at the 
facility level, from associated gas venting at standard conditions, 
in cubic feet.
GOR<INF>p,q</INF> = Gas to oil ratio, for well p in sub-basin q, in 
standard cubic feet of gas per barrel of oil; oil here refers to 
hydrocarbon liquids produced of all API gravities.
V<INF>p,q</INF> = Volume of oil produced, for well p in sub-basin q, 
in barrels in the calendar year during time periods in which 
associated gas was vented or flared.
SG<INF>p,q</INF> = Volume of associated gas sent to sales, for well 
p in sub-basin q, in standard cubic feet of gas in the calendar year 
during time periods in which associated gas was vented or flared.
x = Total number of wells in sub-basin that vent or flare associated 
gas.
y = Total number of sub-basins in a basin that contain wells that 
vent or flare associated gas.

    (4) Calculate both CH<INF>4</INF> and CO<INF>2</INF> volumetric and 
mass emissions from volumetric natural gas emissions using calculations 
in paragraphs (u) and (v) of this section.
    (5) Calculate emissions from associated natural gas if emissions 
are routed to a flare as specified in paragraphs (m)(5)(i) and (ii) of 
this section.
    (i) Use the associated natural gas volume and gas composition as 
determined in paragraph (m)(1) through (4) of this section.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this section to determine associated gas emissions from the flare.
    (n) Flare stack emissions. Calculate CO<INF>2</INF>, 
CH<INF>4</INF>, and N<INF>2</INF>O emissions from a flare stack as 
specified in paragraphs (n)(1) through (9) of this section.
    (1) If you have a continuous flow measurement device on the flare, 
you must use the measured flow volumes to calculate the flare gas 
emissions. If all of the flare gas is not measured by the existing flow 
measurement device, then the flow not measured can be estimated using 
engineering calculations based on best available data or company 
records. If you do not have a continuous flow measurement device on the 
flare, you can use engineering calculations based on process knowledge, 
company records, and best available data.
    (2) If you have a continuous gas composition analyzer on gas to the 
flare, you must use these compositions in calculating emissions. If you 
do not have a continuous gas composition analyzer on gas to the flare, 
you must use the appropriate gas compositions for each stream of 
hydrocarbons going to the flare as specified in paragraphs (n)(2)(i) 
through (iii) of this section.
    (i) For onshore natural gas production, determine the GHG mole 
fraction using paragraph (u)(2)(i) of this section.
    (ii) For onshore natural gas processing, when the stream going to 
flare is natural gas, use the GHG mole fraction in feed natural gas for 
all streams 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 fraction in feed natural 
gas liquid for all streams.
    (iii) For any industry segment required to report to flare stack 
emissions under Sec.  98.232, 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.
    (3) Determine flare combustion efficiency from manufacturer. If not 
available, assume that flare combustion efficiency is 98 percent.
    (4) Convert GHG volumetric emissions to standard conditions using 
calculations in paragraph (t) of this section.
    (5) Calculate GHG volumetric emissions from flaring at standard 
conditions using Equations W-19 and W-20 of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.044

Where:

E<INF>s,CH4</INF> = Annual CH<INF>4</INF> emissions from flare stack 
in cubic feet, at standard conditions.
E<INF>s,CO2</INF> = Annual CO<INF>2</INF> emissions from flare stack 
in cubic feet, at standard conditions.
V<INF>s</INF> = Volume of gas sent to flare in standard cubic feet, 
during the year as determined in paragraph (n)(1) of this section.
[eta] = Flare combustion efficiency, expressed as fraction of gas 
combusted by a burning flare (default is 0.98).
X<INF>CH4</INF> = Mole fraction of CH<INF>4</INF> in the feed gas to 
the flare as determined in paragraph (n)(2) of this section.
X<INF>CO2</INF> = Mole fraction of CO<INF>2</INF> in the feed gas to 
the flare as determined in paragraph (n)(2) of this section.
Z<INF>U</INF> = Fraction of the feed gas sent to an un-lit flare 
determined by engineering estimate and process knowledge based on 
best available data and operating records.
Z<INF>L</INF> = Fraction of the feed gas sent to a burning flare 
(equal to 1 - Z<INF>U</INF>).
Y<INF>j</INF> = Mole fraction of hydrocarbon constituents j (such as 
methane, ethane, propane, butane, and pentanes-plus) in the feed gas 
to the flare as determined in paragraph (n)(1) of this section.
R<INF>j</INF> = Number of carbon atoms in the hydrocarbon 
constituent j in the feed gas to the flare: 1 for methane, 2 for 
ethane, 3 for propane, 4 for butane, and 5 for pentanes-plus).

    (6) Calculate both CH<INF>4</INF> and CO<INF>2</INF> mass emissions 
from volumetric emissions using calculation in paragraph (v) of this 
section.
    (7) Calculate N<INF>2</INF>O emissions from flare stacks using 
Equation W-40 in paragraph (z) of this section.
    (8) If you operate and maintain a CEMS that has both a 
CO<INF>2</INF> concentration monitor and volumetric flow rate monitor 
for the combustion gases from the flare, you must calculate only 
CO<INF>2</INF> emissions for the flare. You must follow the Tier 4 
Calculation Method 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 (7) of this section are not required.
    (9) The flare emissions determined under this paragraph (n) must be 
corrected for flare emissions calculated and reported under other 
paragraphs of

[[Page 70398]]

this section to avoid double counting of these emissions.
    (o) Centrifugal compressor venting. If you are required to report 
emissions from centrifugal compressor venting as specified in Sec.  
98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2), you must conduct 
volumetric emission measurements specified in paragraph (o)(1) of this 
section using methods specified in paragraphs (o)(2) through (5) of 
this section; perform calculations specified in paragraphs (o)(6) 
through (9) of this section; and calculate CH<INF>4</INF> and 
CO<INF>2</INF> mass emissions as specified in paragraph (o)(11) of this 
section. If emissions from a compressor source are routed to a flare, 
paragraphs (o)(1) through (11) of this section do not apply and instead 
you must calculate CH<INF>4</INF>, CO<INF>2</INF>, and N<INF>2</INF>O 
emissions as specified in paragraph (o)(12) of this section. If 
emissions from a compressor source are captured for fuel use or are 
routed to a thermal oxidizer, paragraphs (o)(1) through (12) of this 
section do not apply and instead you must calculate and report 
emissions as specified in subpart C of this part. If emissions from a 
compressor source are routed to vapor recovery, paragraphs (o)(1) 
through (12) of this section do not apply. If you are required to 
report emissions from centrifugal compressor venting at an onshore 
petroleum and natural gas production facility as specified in Sec.  
98.232(c)(19), you must calculate volumetric emissions as specified in 
paragraph (o)(10) of this section; and calculate CH<INF>4</INF> and 
CO<INF>2</INF> mass emissions as specified in paragraph (o)(11) of this 
section.
    (1) General requirements for conducting volumetric emission 
measurements. You must conduct volumetric emission measurements on each 
centrifugal compressor as specified in this paragraph. Compressor 
sources (as defined in Sec.  98.238) without manifolded vents must use 
a measurement method specified in paragraph (o)(1)(i) or (ii) of this 
section. Manifolded compressor sources (as defined in Sec.  98.238) 
must use a measurement method specified in paragraph (o)(1)(i), (ii), 
(iii), or (iv) of this section.
    (i) Centrifugal compressor source as found measurements. Measure 
venting from each compressor according to either paragraph (o)(1)(i)(A) 
or (B) of this section at least once annually, based on the compressor 
mode (as defined in Sec.  98.238) in which the compressor was found at 
the time of measurement, except as specified in paragraphs (o)(1)(i)(C) 
and (D) of this section. If additional measurements beyond the required 
annual testing are performed (including duplicate measurements or 
measurement of additional operating modes), then all measurements 
satisfying the applicable monitoring and QA/QC that is required by this 
paragraph (o) must be used in the calculations specified in this 
section.
    (A) For a compressor measured in operating-mode, you must measure 
volumetric emissions from blowdown valve leakage through the blowdown 
vent as specified in either paragraph (o)(2)(i)(A) or (B) of this 
section and, if the compressor has wet seal oil degassing vents, 
measure volumetric emissions from wet seal oil degassing vents as 
specified in paragraph (o)(2)(ii) of this section.
    (B) For a compressor measured in not-operating-depressurized-mode, 
you must measure volumetric emissions from isolation valve leakage as 
specified in either paragraph (o)(2)(i)(A), (B), or (C) of this 
section. If a compressor is not operated and has blind flanges in place 
throughout the reporting period, measurement is not required in this 
compressor mode.
    (C) You must measure the compressor as specified in paragraph 
(o)(1)(i)(B) of this section at least once in any three consecutive 
calendar years, provided the measurement can be taken during a 
scheduled shutdown. If three consecutive calendar years occur without 
measuring the compressor in not-operating-depressurized-mode, you must 
measure the compressor as specified in paragraph (o)(1)(i)(B) of this 
section at the next scheduled depressurized shutdown. The requirement 
specified in this paragraph does not apply if the compressor has blind 
flanges in place throughout the reporting year. For purposes of this 
paragraph, a scheduled shutdown means a shutdown that requires a 
compressor to be taken off-line for planned or scheduled maintenance. A 
scheduled shutdown does not include instances when a compressor is 
taken offline due to a decrease in demand but must remain available.
    (D) An annual as found measurement is not required in the first 
year of operation for any new compressor that begins operation after as 
found measurements have been conducted for all existing compressors. 
For only the first year of operation of new compressors, calculate 
emissions according to paragraph (o)(6)(ii) of this section.
    (ii) Centrifugal compressor source continuous monitoring. Instead 
of measuring the compressor source according to paragraph (o)(1)(i) of 
this section for a given compressor, you may elect to continuously 
measure volumetric emissions from a compressor source as specified in 
paragraph (o)(3) of this section.
    (iii) Manifolded centrifugal compressor source as found 
measurements. For a compressor source that is part of a manifolded 
group of compressor sources (as defined in Sec.  98.238), instead of 
measuring the compressor source according to paragraph (o)(1)(i), (ii), 
or (iv) of this section, you may elect to measure combined volumetric 
emissions from the manifolded group of compressor sources by conducting 
measurements at the common vent stack as specified in paragraph (o)(4) 
of this section. The measurements must be conducted at the frequency 
specified in paragraphs (o)(1)(iii)(A) and (B) of this section.
    (A) A minimum of one measurement must be taken for each manifolded 
group of compressor sources in a calendar year.
    (B) The measurement may be performed while the compressors are in 
any compressor mode.
    (iv) Manifolded centrifugal compressor source continuous 
monitoring. For a compressor source that is part of a manifolded group 
of compressor sources, instead of measuring the compressor source 
according to paragraph (o)(1)(i), (ii), or (iii) of this section, you 
may elect to continuously measure combined volumetric emissions from 
the manifolded group of compressor sources as specified in paragraph 
(o)(5) of this section.
    (2) Methods for performing as found measurements from individual 
centrifugal compressor sources. If conducting measurements for each 
compressor source, you must determine the volumetric emissions from 
blowdown valves and isolation valves as specified in paragraph 
(o)(2)(i) of this section, and the volumetric emissions from wet seal 
oil degassing vents as specified in paragraph (o)(2)(ii) of this 
section.
    (i) For blowdown valves on compressors in operating-mode and for 
isolation valves on compressors in not-operating-depressurized-mode, 
determine the volumetric emissions using one of the methods specified 
in paragraphs (o)(2)(i)(A) through (D) of this section.
    (A) Determine the volumetric flow at standard conditions from the 
blowdown vent using calibrated bagging or high volume sampler according 
to methods set forth in Sec.  98.234(c) and Sec.  98.234(d), 
respectively.
    (B) Determine the volumetric flow at standard conditions from the 
blowdown

[[Page 70399]]

vent using a temporary meter such as a vane anemometer according to 
methods set forth in Sec.  98.234(b).
    (C) Use an acoustic leak detection device according to methods set 
forth in Sec.  98.234(a)(5).
    (D) You may choose to use any of the methods set forth in Sec.  
98.234(a) to screen for emissions. If emissions are detected using the 
methods set forth in Sec.  98.234(a), then you must use one of the 
methods specified in paragraph (o)(2)(i)(A) through (C) of this 
section. If emissions are not detected using the methods in Sec.  
98.234(a), then you may assume that the volumetric emissions are zero. 
For the purposes of this paragraph, when using any of the methods in 
Sec.  98.234(a), emissions are detected whenever a leak is detected 
according to the methods.
    (ii) For wet seal oil degassing vents in operating-mode, determine 
vapor volumes at standard conditions, using a temporary meter such as a 
vane anemometer or permanent flow meter according to methods set forth 
in Sec.  98.234(b).
    (3) Methods for continuous measurement from individual centrifugal 
compressor sources. If you elect to conduct continuous volumetric 
emission measurements for an individual compressor source as specified 
in paragraph (o)(1)(ii) of this section, you must measure volumetric 
emissions as specified in paragraphs (o)(3)(i) and (ii) of this 
section.
    (i) Continuously measure the volumetric flow for the individual 
compressor source at standard conditions using a permanent meter 
according to methods set forth in Sec.  98.234(b).
    (ii) If compressor blowdown emissions are included in the metered 
emissions specified in paragraph (o)(3)(i) of this section, the 
compressor blowdown emissions may be included with the reported 
emissions for the compressor source and do not need to be calculated 
separately using the method specified in paragraph (i) of this section 
for blowdown vent stacks.
    (4) Methods for performing as found measurements from manifolded 
groups of centrifugal compressor sources. If conducting measurements 
for a manifolded group of compressor sources, you must measure 
volumetric emissions as specified in paragraphs (o)(4)(i) and (ii) of 
this section.
    (i) Measure at a single point in the manifold downstream of all 
compressor inputs and, if practical, prior to comingling with other 
non-compressor emission sources.
    (ii) Determine the volumetric flow at standard conditions from the 
common stack using one of the methods specified in paragraphs 
(o)(4)(ii)(A) through (E) of this section.
    (A) A temporary meter such as a vane anemometer according the 
methods set forth in Sec.  98.234(b).
    (B) Calibrated bagging according to methods set forth in Sec.  
98.234(c).
    (C) A high volume sampler according to methods set forth Sec.  
98.234(d).
    (D) An acoustic leak detection device according to methods set 
forth in Sec.  98.234(a)(5).
    (E) You may choose to use any of the methods set forth in Sec.  
98.234(a) to screen for emissions. If emissions are detected using the 
methods set forth in Sec.  98.234(a), then you must use one of the 
methods specified in paragraph (o)(4)(ii)(A) through (o)(4)(ii)(D) of 
this section. If emissions are not detected using the methods in Sec.  
98.234(a), then you may assume that the volumetric emissions are zero. 
For the purposes of this paragraph, when using any of the methods in 
Sec.  98.234(a), emissions are detected whenever a leak is detected 
according to the method.
    (5) Methods for continuous measurement from manifolded groups of 
centrifugal compressor sources. If you elect to conduct continuous 
volumetric emission measurements for a manifolded group of compressor 
sources as specified in paragraph (o)(1)(iv) of this section, you must 
measure volumetric emissions as specified in paragraphs (o)(5)(i) 
through (iii) of this section.
    (i) Measure at a single point in the manifold downstream of all 
compressor inputs and, if practical, prior to comingling with other 
non-compressor emission sources.
    (ii) Continuously measure the volumetric flow for the manifolded 
group of compressor sources at standard conditions using a permanent 
meter according to methods set forth in Sec.  98.234(b).
    (iii) If compressor blowdown emissions are included in the metered 
emissions specified in paragraph (o)(5)(ii) of this section, the 
compressor blowdown emissions may be included with the reported 
emissions for the manifolded group of compressor sources and do not 
need to be calculated separately using the method specified in 
paragraph (i) of this section for blowdown vent stacks.
    (6) Method for calculating volumetric GHG emissions from as found 
measurements for individual centrifugal compressor sources. For 
compressor sources measured according to paragraph (o)(1)(i) of this 
section, you must calculate annual GHG emissions from the compressor 
sources as specified in paragraphs (o)(6)(i) through (iv) of this 
section.
    (i) Using Equation W-21 of this section, calculate the annual 
volumetric GHG emissions for each centrifugal compressor mode-source 
combination specified in paragraphs (o)(1)(i)(A) and (B) of this 
section that was measured during the reporting year.
[GRAPHIC] [TIFF OMITTED] TR25NO14.064

Where:

E<INF>s,i,m</INF> = Annual volumetric GHG<INF>i</INF> (either 
CH<INF>4</INF> or CO<INF>2</INF>) emissions for measured compressor 
mode-source combination m, at standard conditions, in cubic feet.
MT<INF>s,m</INF> = Volumetric gas emissions for measured compressor 
mode-source combination m, in standard cubic feet per hour, measured 
according to paragraph (o)(2) of this section. If multiple 
measurements are performed for a given mode-source combination m, 
use the average of all measurements.
T<INF>m</INF> = Total time the compressor is in the mode-source 
combination for which E<INF>s,i,m</INF> is being calculated in the 
reporting year, in hours.
GHG<INF>i,m</INF> = Mole fraction of GHG<INF>i</INF> in the vent gas 
for measured compressor mode-source combination m; use the 
appropriate gas compositions in paragraph (u)(2) of this section.
m = Compressor mode-source combination specified in paragraph 
(o)(1)(i)(A) or (o)(1)(i)(B) of this section that was measured for 
the reporting year.

    (ii) Using Equation W-22 of this section, calculate the annual 
volumetric GHG emissions from each centrifugal compressor mode-source 
combination specified in paragraph (o)(1)(i)(A) and (B) of this section 
that was not measured during the reporting year.

[[Page 70400]]

[GRAPHIC] [TIFF OMITTED] TR25NO14.065

Where:

E<INF>s,i,m</INF> = Annual volumetric GHG<INF>i</INF> (either 
CH<INF>4</INF> or CO<INF>2</INF>) emissions for unmeasured 
compressor mode-source combination m, at standard conditions, in 
cubic feet.
EF<INF>s,m</INF> = Reporter emission factor for compressor mode-
source combination m, in standard cubic feet per hour, as calculated 
in paragraph (o)(6)(iii) of this section.
T<INF>m</INF> = Total time the compressor was in the unmeasured 
mode-source combination m, for which E<INF>s,i,m</INF> is being 
calculated in the reporting year, in hours.
GHG<INF>i,m</INF> = Mole fraction of GHG<INF>i</INF> in the vent gas 
for unmeasured compressor mode-source combination m; use the 
appropriate gas compositions in paragraph (u)(2) of this section.
m = Compressor mode-source combination specified in paragraph 
(o)(1)(i)(A) or (o)(1)(i)(B) of this section that was not measured 
in the reporting year.

    (iii) Using Equation W-23 of this section, develop an emission 
factor for each compressor mode-source combination specified in 
paragraph (o)(1)(i)(A) and (B) of this section. These emission factors 
must be calculated annually and used in Equation W-22 of this section 
to determine volumetric emissions from a centrifugal compressor in the 
mode-source combinations that were not measured in the reporting year.
[GRAPHIC] [TIFF OMITTED] TR25NO14.045

Where:

EF<INF>s,m</INF> = Reporter emission factor to be used in Equation 
W-22 of this section for compressor mode-source combination m, in 
standard cubic feet per hour. The reporter emission factor must be 
based on all compressors measured in compressor mode-source 
combination m in the current reporting year and the preceding two 
reporting years.
MT<INF>s,m,p</INF> = Average volumetric gas emission measurement for 
compressor mode-source combination m, for compressor p, in standard 
cubic feet per hour, calculated using all volumetric gas emission 
measurements (MT<INF>s,m</INF> in Equation W-21 of this section) for 
compressor mode-source combination m for compressor p in the current 
reporting year and the preceding two reporting years.
Count<INF>m</INF> = Total number of compressors measured in 
compressor mode-source combination m in the current reporting year 
and the preceding two reporting years.
m = Compressor mode-source combination specified in paragraph 
(o)(1)(i)(A) or (o)(1)(i)(B) of this section.

    (iv) The reporter emission factor in Equation W-23 of this section 
may be calculated by using all measurements from a single owner or 
operator instead of only using measurements from a single facility. If 
you elect to use this option, the reporter emission factor must be 
applied to all reporting facilities for the owner or operator.
    (7) Method for calculating volumetric GHG emissions from continuous 
monitoring of individual centrifugal compressor sources. For compressor 
sources measured according to paragraph (o)(1)(ii) of this section, you 
must use the continuous volumetric emission measurements taken as 
specified in paragraph (o)(3) of this section and calculate annual 
volumetric GHG emissions associated with the compressor source using 
Equation W-24A of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.066

Where:

E<INF>s,i,v</INF> = Annual volumetric GHG<INF>i</INF> (either 
CH<INF>4</INF> or CO<INF>2</INF>) emissions from compressor source 
v, at standard conditions, in cubic feet.
Q<INF>s,v</INF> = Volumetric gas emissions from compressor source v, 
for reporting year, in standard cubic feet.
GHG<INF>i,v</INF> = Mole fraction of GHG<INF>i</INF> in the vent gas 
for compressor source v; use the appropriate gas compositions in 
paragraph (u)(2) of this section.

    (8) Method for calculating volumetric GHG emissions from as found 
measurements of manifolded groups of centrifugal compressor sources. 
For manifolded groups of compressor sources measured according to 
paragraph (o)(1)(iii) of this section, you must calculate annual 
volumetric GHG emissions using Equation W-24B of this section. If the 
centrifugal compressors included in the manifolded group of compressor 
sources share the manifold with reciprocating compressors, you must 
follow the procedures in either this paragraph (o)(8) or paragraph 
(p)(8) of this section to calculate emissions from the manifolded group 
of compressor sources.
[GRAPHIC] [TIFF OMITTED] TR25NO14.067

Where:

E<INF>s,i,g</INF> = Annual volumetric GHG<INF>i</INF> (either 
CH<INF>4</INF> or CO<INF>2</INF>) emissions for manifolded group of 
compressor sources g, at standard conditions, in cubic feet.
T<INF>g</INF> = Total time the manifolded group of compressor 
sources g had potential for emissions in the reporting year, in 
hours. Include all time during which at least one compressor source 
in the manifolded group of compressor sources g was in a mode-source 
combination specified in either paragraph (o)(1)(i)(A), 
(o)(1)(i)(B), (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this 
section. Default of 8760 hours may be used.
MT<INF>s,g,avg</INF> = Average volumetric gas emissions of all 
measurements performed in the reporting year according to paragraph 
(o)(4) of this section for the manifolded group of compressor 
sources g, in standard cubic feet per hour.
GHG<INF>i,g</INF> = Mole fraction of GHG <INF>i</INF> in the vent 
gas for manifolded group of compressor sources g; use the 
appropriate gas compositions in paragraph (u)(2) of this section.


[[Page 70401]]


    (9) Method for calculating volumetric GHG emissions from continuous 
monitoring of manifolded group of centrifugal compressor sources. For a 
manifolded group of compressor sources measured according to paragraph 
(o)(1)(iv) of this section, you must use the continuous volumetric 
emission measurements taken as specified in paragraph (o)(5) of this 
section and calculate annual volumetric GHG emissions associated with 
each manifolded group of compressor sources using Equation W-24C of 
this section. If the centrifugal compressors included in the manifolded 
group of compressor sources share the manifold with reciprocating 
compressors, you must follow the procedures in either this paragraph 
(o)(9) or paragraph (p)(9) of this section to calculate emissions from 
the manifolded group of compressor sources.
[GRAPHIC] [TIFF OMITTED] TR25NO14.068

Where:

E<INF>s,i,g</INF> = Annual volumetric GHG<INF>i</INF> (either 
CH<INF>4</INF> or CO<INF>2</INF>) emissions from manifolded group of 
compressor sources g, at standard conditions, in cubic feet.
Q<INF>s,g</INF> = Volumetric gas emissions from manifolded group of 
compressor sources g, for reporting year, in standard cubic feet.
GHG<INF>i,g</INF> = Mole fraction of GHG <INF>i</INF> in the vent 
gas for measured manifolded group of compressor sources g; use the 
appropriate gas compositions in paragraph (u)(2) of this section.

    (10) Method for calculating volumetric GHG emissions from wet seal 
oil degassing vents at an onshore petroleum and natural gas production 
facility. You must calculate emissions from centrifugal compressor wet 
seal oil degassing vents at an onshore petroleum and natural gas 
production facility using Equation W-25 of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.069

Where:

E<INF>s,i</INF> = Annual volumetric GHG<INF>i</INF> (either 
CH<INF>4</INF> or CO<INF>2</INF>) emissions from centrifugal 
compressor wet seals, at standard conditions, in cubic feet.
Count = Total number of centrifugal compressors that have wet seal 
oil degassing vents.
EF<INF>i,s</INF> = Emission factor for GHG <INF>i</INF>. Use 1.2 x 
10\7\ standard cubic feet per year per compressor for CH<INF>4</INF> 
and 5.30 x 10\5\ standard cubic feet per year per compressor for 
CO<INF>2</INF> at 60[emsp14][deg]F and 14.7 psia.

    (11) Method for converting from volumetric to mass emissions. You 
must calculate both CH<INF>4</INF> and CO<INF>2</INF> mass emissions 
from volumetric emissions using calculations in paragraph (v) of this 
section.
    (12) General requirements for calculating volumetric GHG emissions 
from centrifugal compressors routed to flares. You must calculate and 
report emissions from all centrifugal compressor sources that are 
routed to a flare as specified in paragraphs (o)(12)(i) through (iii) 
of this section.
    (i) Paragraphs (o)(1) through (11) of this section are not required 
for compressor sources that are routed to a flare.
    (ii) If any compressor sources are routed to a flare, calculate the 
emissions for the flare stack as specified in paragraph (n) of this 
section and report emissions from the flare as specified in Sec.  
98.236(n), without subtracting emissions attributable to compressor 
sources from the flare.
    (iii) Report all applicable activity data for compressors with 
compressor sources routed to flares as specified in Sec.  98.236(o).
    (p) Reciprocating compressor venting. If you are required to report 
emissions from reciprocating compressor venting as specified in Sec.  
98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1), you must conduct 
volumetric emission measurements specified in paragraph (p)(1) of this 
section using methods specified in paragraphs (p)(2) through (5) of 
this section; perform calculations specified in paragraphs (p)(6) 
through (9) of this section; and calculate CH<INF>4</INF> and 
CO<INF>2</INF> mass emissions as specified in paragraph (p)(11) of this 
section. If emissions from a compressor source are routed to a flare, 
paragraphs (p)(1) through (11) of this section do not apply and instead 
you must calculate CH<INF>4</INF>, CO<INF>2</INF>, and N<INF>2</INF>O 
emissions as specified in paragraph (p)(12) of this section. If 
emissions from a compressor source are captured for fuel use or are 
routed to a thermal oxidizer, paragraphs (p)(1) through (12) of this 
section do not apply and instead you must calculate and report 
emissions as specified in subpart C of this part. If emissions from a 
compressor source are routed to vapor recovery, paragraphs (p)(1) 
through (12) of this section do not apply. If you are required to 
report emissions from reciprocating compressor venting at an onshore 
petroleum and natural gas production facility as specified in Sec.  
98.232(c)(11), you must calculate volumetric emissions as specified in 
paragraph (p)(10) of this section; and calculate CH<INF>4</INF> and 
CO<INF>2</INF> mass emissions as specified in paragraph (p)(11) of this 
section.
    (1) General requirements for conducting volumetric emission 
measurements. You must conduct volumetric emission measurements on each 
reciprocating compressor as specified in this paragraph. Compressor 
sources (as defined in Sec.  98.238) without manifolded vents must use 
a measurement method specified in paragraph (p)(1)(i) or (ii) of this 
section. Manifolded compressor sources (as defined in Sec.  98.238) 
must use a measurement method specified in paragraph (p)(1)(i), (ii), 
(iii), or (iv) of this section.
    (i) Reciprocating compressor source as found measurements. Measure 
venting from each compressor according to either paragraph 
(p)(1)(i)(A), (B), or (C) of this section at least once annually, based 
on the compressor mode (as defined in Sec.  98.238) in which the 
compressor was found at the time of measurement, except as specified in 
paragraphs (p)(1)(i)(D) and (E) of this section. If additional 
measurements beyond the required annual testing are performed 
(including duplicate measurements or measurement of additional 
operating modes), then all measurements satisfying the applicable 
monitoring and QA/QC that is required by this paragraph (o) must be 
used in the calculations specified in this section.
    (A) For a compressor measured in operating-mode, you must measure 
volumetric emissions from blowdown valve leakage through the blowdown 
vent as specified in either paragraph (p)(2)(i)(A) or (B) of this 
section, and measure volumetric emissions from

[[Page 70402]]

reciprocating rod packing as specified in paragraph (p)(2)(ii) of this 
section.
    (B) For a compressor measured in standby-pressurized-mode, you must 
measure volumetric emissions from blowdown valve leakage through the 
blowdown vent as specified in either paragraph (p)(2)(i)(A) or (B) of 
this section.
    (C) For a compressor measured in not-operating-depressurized-mode, 
you must measure volumetric emissions from isolation valve leakage as 
specified in either paragraph (p)(2)(i)(A), (B), or (C) of this 
section. If a compressor is not operated and has blind flanges in place 
throughout the reporting period, measurement is not required in this 
compressor mode.
    (D) You must measure the compressor as specified in paragraph 
(p)(1)(i)(C) of this section at least once in any three consecutive 
calendar years, provided the measurement can be taken during a 
scheduled shutdown. If there is no scheduled shutdown within three 
consecutive calendar years, you must measure the compressor as 
specified in paragraph (p)(1)(i)(C) of this section at the next 
scheduled depressurized shutdown. For purposes of this paragraph, a 
scheduled shutdown means a shutdown that requires a compressor to be 
taken off-line for planned or scheduled maintenance. A scheduled 
shutdown does not include instances when a compressor is taken offline 
due to a decrease in demand but must remain available.
    (E) An annual as found measurement is not required in the first 
year of operation for any new compressor that begins operation after as 
found measurements have been conducted for all existing compressors. 
For only the first year of operation of new compressors, calculate 
emissions according to paragraph (p)(6)(ii) of this section.
    (ii) Reciprocating compressor source continuous monitoring. Instead 
of measuring the compressor source according to paragraph (p)(1)(i) of 
this section for a given compressor, you may elect to continuously 
measure volumetric emissions from a compressor source as specified in 
paragraph (p)(3) of this section.
    (iii) Manifolded reciprocating compressor source as found 
measurements. For a compressor source that is part of a manifolded 
group of compressor sources (as defined in Sec.  98.238), instead of 
measuring the compressor source according to paragraph (p)(1)(i), (ii), 
or (iv) of this section, you may elect to measure combined volumetric 
emissions from the manifolded group of compressor sources by conducting 
measurements at the common vent stack as specified in paragraph (p)(4) 
of this section. The measurements must be conducted at the frequency 
specified in paragraphs (p)(1)(iii)(A) and (B) of this section.
    (A) A minimum of one measurement must be taken for each manifolded 
group of compressor sources in a calendar year.
    (B) The measurement may be performed while the compressors are in 
any compressor mode.
    (iv) Manifolded reciprocating compressor source continuous 
monitoring. For a compressor source that is part of a manifolded group 
of compressor sources, instead of measuring the compressor source 
according to paragraph (p)(1)(i), (ii), or (iii) of this section, you 
may elect to continuously measure combined volumetric emissions from 
the manifolded group of compressors sources as specified in paragraph 
(p)(5) of this section.
    (2) Methods for performing as found measurements from individual 
reciprocating compressor sources. If conducting measurements for each 
compressor source, you must determine the volumetric emissions from 
blowdown valves and isolation valves as specified in paragraph 
(p)(2)(i) of this section. You must determine the volumetric emissions 
from reciprocating rod packing as specified in paragraph (p)(2)(ii) or 
(iii) of this section.
    (i) For blowdown valves on compressors in operating-mode or 
standby-pressurized-mode, and for isolation valves on compressors in 
not-operating-depressurized-mode, determine the volumetric emissions 
using one of the methods specified in paragraphs (p)(2)(i)(A) through 
(D) of this section.
    (A) Determine the volumetric flow at standard conditions from the 
blowdown vent using calibrated bagging or high volume sampler according 
to methods set forth in Sec.  98.234(c) and (d), respectively.
    (B) Determine the volumetric flow at standard conditions from the 
blowdown vent using a temporary meter such as a vane anemometer, 
according to methods set forth in Sec.  98.234(b).
    (C) Use an acoustic leak detection device according to methods set 
forth in Sec.  98.234(a)(5).
    (D) You may choose to use any of the methods set forth in Sec.  
98.234(a) to screen for emissions. If emissions are detected using the 
methods set forth in Sec.  98.234(a), then you must use one of the 
methods specified in paragraphs (p)(2)(i)(A) through (C) of this 
section. If emissions are not detected using the methods in Sec.  
98.234(a), then you may assume that the volumetric emissions are zero. 
For the purposes of this paragraph, when using any of the methods in 
Sec.  98.234(a), emissions are detected whenever a leak is detected 
according to the method.
    (ii) For reciprocating rod packing equipped with an open-ended vent 
line on compressors in operating-mode, determine the volumetric 
emissions using one of the methods specified in paragraphs 
(p)(2)(ii)(A) through (C) of this section.
    (A) Determine the volumetric flow at standard conditions from the 
open-ended vent line using calibrated bagging or high volume sampler 
according to methods set forth in Sec.  98.234(c) and (d), 
respectively.
    (B) Determine the volumetric flow at standard conditions from the 
open-ended vent line using a temporary meter such as a vane anemometer, 
according to methods set forth in Sec.  98.234(b).
    (C) You may choose to use any of the methods set forth in Sec.  
98.234(a) to screen for emissions. If emissions are detected using the 
methods set forth in Sec.  98.234(a), then you must use one of the 
methods specified in paragraph (p)(2)(ii)(A) and (p)(4)(ii)(B) of this 
section. If emissions are not detected using the methods in Sec.  
98.234(a), then you may assume that the volumetric emissions are zero. 
For the purposes of this paragraph, when using any of the methods in 
Sec.  98.234(a), emissions are detected whenever a leak is detected 
according to the method.
    (iii) For reciprocating rod packing not equipped with an open-ended 
vent line on compressors in operating-mode, you must determine the 
volumetric emissions using the method specified in paragraphs 
(p)(2)(iii)(A) and (B) of this section.
    (A) You must use the methods described in Sec.  98.234(a) to 
conduct annual leak detection of equipment leaks from the packing case 
into an open distance piece, or for compressors with a closed distance 
piece, conduct annual detection of gas emissions from the rod packing 
vent, distance piece vent, compressor crank case breather cap, or other 
vent emitting gas from the rod packing.
    (B) You must measure emissions found in paragraph (p)(2)(iii)(A) of 
this section using an appropriate meter, calibrated bag, or high volume 
sampler according to methods set forth in Sec.  98.234(b), (c), and 
(d), respectively.
    (3) Methods for continuous measurement from individual 
reciprocating compressor sources. If you elect to conduct continuous 
volumetric emission measurements for an

[[Page 70403]]

individual compressor source as specified in paragraph (p)(1)(ii) of 
this section, you must measure volumetric emissions as specified in 
paragraphs (p)(3)(i) and (p)(3)(ii) of this section.
    (i) Continuously measure the volumetric flow for the individual 
compressor sources at standard conditions using a permanent meter 
according to methods set forth in Sec.  98.234(b).
    (ii) If compressor blowdown emissions are included in the metered 
emissions specified in paragraph (p)(3)(i) of this section, the 
compressor blowdown emissions may be included with the reported 
emissions for the compressor source and do not need to be calculated 
separately using the method specified in paragraph (i) of this section 
for blowdown vent stacks.
    (4) Methods for performing as found measurements from manifolded 
groups of reciprocating compressor sources. If conducting measurements 
for a manifolded group of compressor sources, you must measure 
volumetric emissions as specified in paragraphs (p)(4)(i) and (ii) of 
this section.
    (i) Measure at a single point in the manifold downstream of all 
compressor inputs and, if practical, prior to comingling with other 
non-compressor emission sources.
    (ii) Determine the volumetric flow at standard conditions from the 
common stack using one of the methods specified in paragraph 
(p)(4)(ii)(A) through (E) of this section.
    (A) A temporary meter such as a vane anemometer according the 
methods set forth in Sec.  98.234(b).
    (B) Calibrated bagging according to methods set forth in Sec.  
98.234(c).
    (C) A high volume sampler according to methods set forth Sec.  
98.234(d).
    (D) An acoustic leak detection device according to methods set 
forth in Sec.  98.234(a)(5).
    (E) You may choose to use any of the methods set forth in Sec.  
98.234(a) to screen for emissions. If emissions are detected using the 
methods set forth in Sec.  98.234(a), then you must use one of the 
methods specified in paragraph (p)(4)(ii)(A) through (D) of this 
section. If emissions are not detected using the methods in Sec.  
98.234(a), then you may assume that the volumetric emissions are zero. 
For the purposes of this paragraph, when using any of the methods in 
Sec.  98.234(a), emissions are detected whenever a leak is detected 
according to the method.
    (5) Methods for continuous measurement from manifolded groups of 
reciprocating compressor sources. If you elect to conduct continuous 
volumetric emission measurements for a manifolded group of compressor 
sources as specified in paragraph (p)(1)(iv) of this section, you must 
measure volumetric emissions as specified in paragraphs (p)(5)(i) 
through (iii) of this section.
    (i) Measure at a single point in the manifold downstream of all 
compressor inputs and, if practical, prior to comingling with other 
non-compressor emission sources.
    (ii) Continuously measure the volumetric flow for the manifolded 
group of compressor sources at standard conditions using a permanent 
meter according to methods set forth in Sec.  98.234(b).
    (iii) If compressor blowdown emissions are included in the metered 
emissions specified in paragraph (p)(5)(ii) of this section, the 
compressor blowdown emissions may be included with the reported 
emissions for the manifolded group of compressor sources and do not 
need to be calculated separately using the method specified in 
paragraph (i) of this section for blowdown vent stacks.
    (6) Method for calculating volumetric GHG emissions from as found 
measurements for individual reciprocating compressor sources. For 
compressor sources measured according to paragraph (p)(1)(i) of this 
section, you must calculate GHG emissions from the compressor sources 
as specified in paragraphs (p)(6)(i) through (iv) of this section.
    (i) Using Equation W-26 of this section, calculate the annual 
volumetric GHG emissions for each reciprocating compressor mode-source 
combination specified in paragraphs (p)(1)(i)(A) through (C) of this 
section that was measured during the reporting year.
[GRAPHIC] [TIFF OMITTED] TR25NO14.070


Where:

E<INF>s,i,m</INF> = Annual volumetric GHG<INF>i</INF> (either 
CH<INF>4</INF> or CO<INF>2</INF>) emissions for measured compressor 
mode-source combination m, at standard conditions, in cubic feet.
MT<INF>s,m</INF> = Volumetric gas emissions for measured compressor 
mode-source combination m, in standard cubic feet per hour, measured 
according to paragraph (p)(2) of this section. If multiple 
measurements are performed for a given mode-source combination m, 
use the average of all measurements.
T<INF>m</INF> = Total time the compressor is in the mode-source 
combination m, for which E<INF>s,i,m</INF> is being calculated in 
the reporting year, in hours.
GHG<INF>i,m</INF> = Mole fraction of GHG<INF>i</INF> in the vent gas 
for measured compressor mode-source combination m; use the 
appropriate gas compositions in paragraph (u)(2) of this section.
m = Compressor mode-source combination specified in paragraph 
(p)(1)(i)(A), (B), or (C) of this section that was measured for the 
reporting year.

    (ii) Using Equation W-27 of this section, calculate the annual 
volumetric GHG emissions from each reciprocating compressor mode-source 
combination specified in paragraph (p)(1)(i)(A), (B), and (C) of this 
section that was not measured during the reporting year.
[GRAPHIC] [TIFF OMITTED] TR25NO14.046


Where:

E<INF>s,i,m</INF> = Annual volumetric GHG<INF>i</INF> (either 
CH<INF>4</INF> or CO<INF>2</INF>) emissions for unmeasured 
compressor mode-source combination m, at standard conditions, in 
cubic feet.
EF<INF>s,m</INF> = Reporter emission factor for compressor mode-
source combination m, in standard cubic feet per hour, as calculated 
in paragraph (p)(6)(iii) of this section.
T<INF>m</INF> = Total time the compressor was in the unmeasured 
mode-source combination m, for which E<INF>s,i,m</INF> is being 
calculated in the reporting year, in hours.
GHG<INF>i,m</INF> = Mole fraction of GHG<INF>i</INF> in the vent gas 
for unmeasured compressor mode-source combination m; use the 
appropriate gas compositions in paragraph (u)(2) of this section.
m = Compressor mode-source combination specified in paragraph 
(p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section that was 
not measured for the reporting year.

    (iii) Using Equation W-28 of this section, develop an emission 
factor for

[[Page 70404]]

each compressor mode-source combination specified in paragraph 
(p)(1)(i)(A), (B), and (C) of this section. These emission factors must 
be calculated annually and used in Equation W-27 of this section to 
determine volumetric emissions from a reciprocating compressor in the 
mode-source combinations that were not measured in the reporting year.
[GRAPHIC] [TIFF OMITTED] TR25NO14.047


Where:

EF<INF>s,m</INF> = Reporter emission factor to be used in Equation 
W-27 of this section for compressor mode-source combination m, in 
standard cubic feet per hour. The reporter emission factor must be 
based on all compressors measured in compressor mode-source 
combination m in the current reporting year and the preceding two 
reporting years.
MT<INF>s,m,p</INF> = Average volumetric gas emission measurement for 
compressor mode-source combination m, for compressor p, in standard 
cubic feet per hour, calculated using all volumetric gas emission 
measurements (MT<INF>s,m</INF> in Equation W-26 of this section) for 
compressor mode-source combination m for compressor p in the current 
reporting year and the preceding two reporting years.
Count<INF>m</INF> = Total number of compressors measured in 
compressor mode-source combination m in the current reporting year 
and the preceding two reporting years.
m = Compressor mode-source combination specified in paragraph 
(p)(1)(i)(A), (B), or (C) of this section.

    (iv) The reporter emission factor in Equation W-28 of this section 
may be calculated by using all measurements from a single owner or 
operator instead of only using measurements from a single facility. If 
you elect to use this option, the reporter emission factor must be 
applied to all reporting facilities for the owner or operator.
    (7) Method for calculating volumetric GHG emissions from continuous 
monitoring of individual reciprocating compressor sources. For 
compressor sources measured according to paragraph (p)(1)(ii) of this 
section, you must use the continuous volumetric emission measurements 
taken as specified in paragraph (p)(3) of this section and calculate 
annual volumetric GHG emissions associated with the compressor source 
using Equation W-29A of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.071


Where:

E<INF>s,i,v</INF> = Annual volumetric GHG<INF>i</INF> (either 
CH<INF>4</INF> or CO<INF>2</INF>) emissions from compressor source 
v, at standard conditions, in cubic feet.
Q<INF>s,v</INF> = Volumetric gas emissions from compressor source v, 
for reporting year, in standard cubic feet.
GHG<INF>i,v</INF> = Mole fraction of GHG<INF>i</INF> in the vent gas 
for compressor source v; use the appropriate gas compositions in 
paragraph (u)(2) of this section.

    (8) Method for calculating volumetric GHG emissions from as found 
measurements of manifolded groups of reciprocating compressor sources. 
For manifolded groups of compressor sources measured according to 
paragraph (p)(1)(iii) of this section, you must calculate annual GHG 
emissions using Equation W-29B of this section. If the reciprocating 
compressors included in the manifolded group of compressor sources 
share the manifold with centrifugal compressors, you must follow the 
procedures in either this paragraph (p)(8) or paragraph (o)(8) of this 
section to calculate emissions from the manifolded group of compressor 
sources.
[GRAPHIC] [TIFF OMITTED] TR25NO14.072


Where:

E<INF>s,i,g</INF> = Annual volumetric GHG<INF>i</INF> (either 
CH<INF>4</INF> or CO<INF>2</INF>) emissions for manifolded group of 
compressor sources g, at standard conditions, in cubic feet.
T<INF>g</INF> = Total time the manifolded group of compressor 
sources g had potential for emissions in the reporting year, in 
hours. Include all time during which at least one compressor source 
in the manifolded group of compressor sources g was in a mode-source 
combination specified in either paragraph (o)(1)(i)(A), 
(o)(1)(i)(B), (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this 
section. Default of 8760 hours may be used.
MT<INF>s,g,avg</INF> = Average volumetric gas emissions of all 
measurements performed in the reporting year according to paragraph 
(p)(4) of this section for the manifolded group of compressor 
sources g, in standard cubic feet per hour.
GHG<INF>i,g</INF> = Mole fraction of GHG<INF>i</INF> in the vent gas 
for manifolded group of compressor sources g; use the appropriate 
gas compositions in paragraph (u)(2) of this section.

    (9) Method for calculating volumetric GHG emissions from continuous 
monitoring of manifolded group of reciprocating compressor sources. For 
a manifolded group of compressor sources measured according to 
paragraph (p)(1)(iv) of this section, you must use the continuous 
volumetric emission measurements taken as specified in paragraph (p)(5) 
of this section and calculate annual volumetric GHG emissions 
associated with each manifolded group of compressor sources using 
Equation W-29C of this section. If the reciprocating compressors 
included in the manifolded group of compressor sources share the 
manifold with centrifugal compressors, you must follow the procedures 
in either this paragraph (p)(9) or paragraph (o)(9) of this section to 
calculate emissions from the manifolded group of compressor sources.

[[Page 70405]]

[GRAPHIC] [TIFF OMITTED] TR25NO14.073


Where:

E<INF>s,i,g</INF> = Annual volumetric GHG<INF>i</INF> (either 
CH<INF>4</INF> or CO<INF>2</INF>) emissions from manifolded group of 
compressor sources g, at standard conditions, in cubic feet.
Q<INF>s,g</INF> = Volumetric gas emissions from manifolded group of 
compressor sources g, for reporting year, in standard cubic feet.
GHG<INF>i,g</INF> = Mole fraction of GHG<INF>i</INF> in the vent gas 
for measured manifolded group of compressor sources g; use the 
appropriate gas compositions in paragraph (u)(2) of this section.

    (10) Method for calculating volumetric GHG emissions from 
reciprocating compressor venting at an onshore petroleum and natural 
gas production facility. You must calculate emissions from 
reciprocating compressor venting at an onshore petroleum and natural 
gas production facility using Equation W-29D of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.074


Where:

E<INF>s,i</INF> = Annual volumetric GHG<INF>i</INF> (either 
CH<INF>4</INF> or CO<INF>2</INF>) emissions from reciprocating 
compressors, at standard conditions, in cubic feet.
Count = Total number of reciprocating compressors.
EF<INF>i,s</INF> = Emission factor for GHG<INF>i</INF>. Use 9.48 x 
10\3\ standard cubic feet per year per compressor for CH<INF>4</INF> 
and 5.27 x 10\2\ standard cubic feet per year per compressor for 
CO<INF>2</INF> at 60[emsp14][deg]F and 14.7 psia.

    (11) Method for converting from volumetric to mass emissions. You 
must calculate both CH<INF>4</INF> and CO<INF>2</INF> mass emissions 
from volumetric emissions using calculations in paragraph (v) of this 
section.
    (12) General requirements for calculating volumetric GHG emissions 
from reciprocating compressors routed to flares. You must calculate and 
report emissions from all reciprocating compressor sources that are 
routed to a flare as specified in paragraphs (p)(12)(i) through (iii) 
of this section.
    (i) Paragraphs (p)(1) through (11) of this section are not required 
for compressor sources that are routed to a flare.
    (ii) If any compressor sources are routed to a flare, calculate the 
emissions for the flare stack as specified in paragraph (n) of this 
section and report emissions from the flare as specified in Sec.  
98.236(n), without subtracting emissions attributable to compressor 
sources from the flare.
    (iii) Report all applicable activity data for compressors with 
compressor sources routed to flares as specified in Sec.  98.236(p).
    (q) Equipment leak surveys. You must use the methods described in 
Sec.  98.234(a) to conduct leak detection(s) of equipment leaks from 
all component types listed in Sec.  98.232(d)(7), (e)(7), (f)(5), 
(g)(3), (h)(4), and (i)(1). This paragraph (q) applies to component 
types in streams with gas content greater than 10 percent 
CH<INF>4</INF> plus CO<INF>2</INF> by weight. Component types in 
streams with gas content less than or equal to 10 percent 
CH<INF>4</INF> plus CO<INF>2</INF> by weight are exempt from the 
requirements of this paragraph (q) and do not need to be reported. 
Tubing systems equal to or less than one half inch diameter are exempt 
from the requirements of this paragraph (q) and do not need to be 
reported. For industry segments listed in Sec.  98.230(a)(3) through 
(8), if equipment leaks are detected for component types listed in this 
paragraph (q), then you must calculate equipment leak emissions per 
component type per reporting facility using Equation W-30 of this 
section. For the industry segment listed in Sec.  98.230(a)(8), the 
results from Equation W-30 are used to calculate population emission 
factors on a meter/regulator run basis using Equation W-31 of this 
section. If you chose to conduct equipment leak surveys at all above 
grade transmission-distribution transfer stations over multiple years, 
``n,'' according to paragraph (q)(8)(i) of this section, then you must 
calculate the emissions from all above grade transmission-distribution 
transfer stations as specified in paragraph (q)(9) of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.048


Where:

E<INF>s,p,i</INF> = Annual total volumetric emissions of 
GHG<INF>i</INF> from specific component type ``p'' (listed in Sec.  
98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1)) in 
standard (``s'') cubic feet, as specified in paragraphs (q)(1) 
through (q)(8) of this section.
x<INF>p</INF> = Total number of specific component type ``p'' 
detected as leaking during annual leak surveys.
EF<INF>s,p</INF> = Leaker emission factor for specific component 
types listed in Table W-2 through Table W-7 of this subpart.
GHG<INF>i</INF> = For onshore natural gas processing facilities, 
concentration of GHG<INF>i</INF>, CH<INF>4</INF> or CO<INF>2</INF>, 
in the total hydrocarbon of the feed natural gas; for onshore 
natural gas transmission compression and underground natural gas 
storage, GHG<INF>i</INF> equals 0.975 for CH<INF>4</INF> and 1.1 x 
10<SUP>-2</SUP> for CO<INF>2</INF> ; for LNG storage and LNG import 
and export equipment, GHG<INF>i</INF> equals 1 for CH<INF>4</INF> 
and 0 for CO<INF>2</INF> ; and for natural gas distribution, 
GHG<INF>i</INF> equals 1 for CH<INF>4</INF> and 1.1 x 
10<SUP>-2</SUP> CO<INF>2</INF>.
T<INF>p,z</INF> = The total time the surveyed component ``z'', 
component type ``p'', was assumed to be leaking and operational, in 
hours. If one leak detection survey is conducted in the calendar 
year, assume the component was leaking for the entire calendar year, 
accounting for time the component was not operational (i.e., not 
operating under pressure) using engineering estimate based on best 
available data. If multiple leak detection surveys are conducted in 
the calendar year, assume that the component found to be leaking has 
been leaking since the previous survey (if not found leaking in the 
previous survey) or the beginning of the calendar year (if it was 
found leaking in the previous survey), accounting for time the 
component was not operational using engineering estimate based on 
best available data. 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, accounting for time the 
component was not operational using engineering estimate based on 
best available data.

    (1) You must conduct either one leak detection survey in a calendar 
year or multiple complete leak detection

[[Page 70406]]

surveys in a calendar year. The leak detection surveys selected must be 
conducted during the calendar year.
    (2) Calculate both CO<INF>2</INF> and CH<INF>4</INF> mass emissions 
using calculations in paragraph (v) of this section.
    (3) Onshore natural gas processing facilities must use the 
appropriate default total hydrocarbon leaker emission factors for 
compressor components in gas service and non-compressor components in 
gas service listed in Table W-2 of this subpart.
    (4) Onshore natural gas transmission compression facilities must 
use the appropriate default total hydrocarbon leaker emission factors 
for compressor components in gas service and non-compressor components 
in gas service listed in Table W-3 of this subpart.
    (5) Underground natural gas storage facilities must use the 
appropriate default total hydrocarbon leaker emission factors for 
storage stations in gas service listed in Table W-4 of this subpart.
    (6) LNG storage facilities must use the appropriate default methane 
leaker emission factors for LNG storage components in gas service 
listed in Table W-5 of this subpart.
    (7) LNG import and export facilities must use the appropriate 
default methane leaker emission factors for LNG terminals components in 
LNG service listed in Table W-6 of this subpart.
    (8) Natural gas distribution facilities must use Equation W-30 of 
this section and the default methane leaker emission factors for 
transmission-distribution transfer station components in gas service 
listed in Table W-7 of this subpart to calculate component emissions 
from annual equipment leak surveys conducted at above grade 
transmission-distribution transfer stations. Natural gas distribution 
facilities are required to perform equipment leak surveys only at above 
grade stations that qualify as transmission-distribution transfer 
stations. Below grade transmission-distribution transfer stations and 
all metering-regulating stations that do not meet the definition of 
transmission-distribution transfer stations are not required to perform 
equipment leak surveys under this section.
    (i) Natural gas distribution facilities may choose to conduct 
equipment leak surveys at all above grade transmission-distribution 
transfer stations over multiple years ``n'', not exceeding a five year 
period to cover all above grade transmission-distribution transfer 
stations. If the facility chooses to use the multiple year option, then 
the number of transmission-distribution transfer stations that are 
monitored in each year should be approximately equal across all years 
in the cycle.
    (ii) Use Equation W-31 of this section to determine the meter/
regulator run population emission factors for each GHG<INF>i</INF>. As 
additional survey data become available, you must recalculate the 
meter/regulator run population emission factors for each 
GHG<INF>i</INF> annually according to paragraph (q)(8)(iii) of this 
section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.049

Where:

EF<INF>s,MR,i</INF> = Meter/regulator run population emission factor 
for GHG<INF>i</INF> based on all surveyed above grade transmission-
distribution transfer stations over ``n'' years, in standard cubic 
feet of GHG<INF>i</INF> per operational hour of all meter/regulator 
runs.
E<INF>s,p,i,y</INF> = Annual total volumetric emissions at standard 
conditions of GHG<INF>i</INF> from component type ``p'' during year 
``y'' in standard (``s'') cubic feet, as calculated using Equation 
W-30 of this section.
p = Seven component types listed in Table W-7 of this subpart for 
transmission-distribution transfer stations.
T<INF>w,y</INF> = The total time the surveyed meter/regulator run 
``w'' was operational, in hours during survey year ``y'' using 
engineering estimate based on best available data.
Count<INF>MR,y</INF> = Count of meter/regulator runs surveyed at 
above grade transmission-distribution transfer stations in year 
``y''.
y = Year of data included in emission factor ``EF<INF>s,MR,i</INF>'' 
according to paragraph (q)(8)(iii) of this section.
n = Number of years of data, according to paragraph (q)(8)(i) of 
this section, whose results are used to calculate emission factor 
``EF<INF>s,MR,i</INF>'' according to paragraph (q)(8)(iii) of this 
section.

    (iii) The emission factor ``EF<INF>s,MR,i</INF>'', based on annual 
equipment leak surveys at above grade transmission-distribution 
transfer stations, must be calculated annually. If you chose to conduct 
equipment leak surveys at all above grade transmission-distribution 
transfer stations over multiple years, ``n,'' according to paragraph 
(q)(8)(i) of this section and you have submitted a smaller number of 
annual reports than the duration of the selected cycle period of 5 
years or less, then all available data from the current year and 
previous years must be used in the calculation of the emission factor 
``EF<INF>s,MR,i</INF>'' from Equation W-31 of this section. After the 
first survey cycle of ``n'' years is completed and beginning in 
calendar year (n+1), the survey will continue on a rolling basis by 
including the survey results from the current calendar year ``y'' and 
survey results from all previous (n-1) calendar years, such that each 
annual calculation of the emission factor ``EF<INF>s,MR,i</INF>'' from 
Equation W-31 of this section is based on survey results from ``n'' 
years. Upon completion of a cycle, you may elect to change the number 
of years in the next cycle period (to be 5 years or less). If the 
number of years in the new cycle is greater than the number of years in 
the previous cycle, calculate ``EF<INF>s,MR,i</INF>'' from Equation W-
31 of this section in each year of the new cycle using the survey 
results from the current calendar year and the survey results from the 
preceding number years that is equal to the number of years in the 
previous cycle period. If the number of years, ``n<INF>new</INF>'', in 
the new cycle is smaller than the number of years in the previous 
cycle, ``n'', calculate ``EF<INF>s,MR,i</INF>'' from Equation W-31 of 
this section in each year of the new cycle using the survey results 
from the current calendar year and survey results from all previous 
(n<INF>new</INF>-1) calendar years.
    (9) If you chose to conduct equipment leak surveys at all above 
grade transmission-distribution transfer stations over multiple years, 
``n,'' according to paragraph (q)(8)(i) of this section, you must use 
the meter/regulator run population emission factors calculated using 
Equation W-31 of this section and the total count of all meter/
regulator runs at above grade transmission-distribution transfer 
stations to calculate emissions from all above grade transmission-
distribution transfer stations using Equation W-32B in paragraph (r) of 
this section.

[[Page 70407]]

    (r) Equipment leaks by population count. This paragraph applies to 
emissions sources listed in Sec.  98.232 (c)(21), (f)(5), (g)(3), 
(h)(4), (i)(2), (i)(3), (i)(4), (i)(5), and (i)(6) on streams with gas 
content greater than 10 percent CH<INF>4</INF> plus CO<INF>2</INF> by 
weight. Emissions sources in streams with gas content less than or 
equal to 10 percent CH<INF>4</INF> plus CO<INF>2</INF> by weight are 
exempt from the requirements of this paragraph (r) and do not need to 
be reported. Tubing systems equal to or less than one half inch 
diameter are exempt from the requirements of paragraph (r) of this 
section and do not need to be reported. You must calculate emissions 
from all emission sources listed in this paragraph using Equation W-32A 
of this section, except for natural gas distribution facility emission 
sources listed in Sec.  98.232(i)(3). Natural gas distribution facility 
emission sources listed in Sec.  98.232(i)(3) must calculate emissions 
using Equation W-32B and according to paragraph (r)(6)(ii) of this 
section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.075

Where:

E<INF>s,e,i</INF> = Annual volumetric emissions of GHG<INF>i</INF> 
from the emission source type in standard cubic feet. The emission 
source type may be a component (e.g. connector, open-ended line, 
etc.), below grade metering-regulating station, below grade 
transmission-distribution transfer station, distribution main, or 
distribution service.
E<INF>s,MR,i</INF> = Annual volumetric emissions of GHG<INF>i</INF> 
from all meter/regulator runs at above grade metering regulating 
stations that are not above grade transmission-distribution transfer 
stations or, when used to calculate emissions according to paragraph 
(q)(9) of this section, the annual volumetric emissions of 
GHG<INF>i</INF> from all meter/regulator runs at above grade 
transmission-distribution transfer stations, in standard cubic feet.
Count<INF>e</INF> = Total number of the emission source type at the 
facility. For onshore petroleum and natural gas production 
facilities, 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 facilities must count each component listed in 
Table W-4 of this subpart. LNG storage facilities must count the 
number of vapor recovery compressors. LNG import and export 
facilities must count the number of vapor recovery compressors. 
Natural gas distribution facilities must count: (1) The number of 
distribution services by material type; (2) miles of distribution 
mains by material type; and (3) number of below grade metering-
regulating stations, by pressure type; as listed in Table W-7 of 
this subpart.
Count<INF>MR</INF> = Total number of meter/regulator runs at above 
grade metering-regulating stations that are not above grade 
transmission-distribution transfer stations or, when used to 
calculate emissions according to paragraph (q)(9) of this section, 
the total number of meter/regulator runs at above grade 
transmission-distribution transfer stations.
EF<INF>s,e</INF> = Population emission factor for the specific 
emission source type, as listed in Tables W-1A and W-4 through 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<INF>s,MR,i</INF> = Meter/regulator run population emission factor 
for GHG<INF>i</INF> based on all surveyed above grade transmission-
distribution transfer stations over ``n'' years, in standard cubic 
feet of GHG<INF>i</INF> per operational hour of all meter/regulator 
runs, as determined in Equation W-31.
GHG<INF>i</INF> = For onshore petroleum and natural gas production 
facilities, concentration of GHG<INF>i</INF>, CH<INF>4</INF>, or 
CO<INF>2</INF>, in produced natural gas as defined in paragraph 
(u)(2) of this section; for onshore natural gas transmission 
compression and underground natural gas storage, GHG<INF>i</INF> 
equals 0.975 for CH<INF>4</INF> and 1.1 x 10 <SUP>-2</SUP> for 
CO<INF>2</INF>; for LNG storage and LNG import and export equipment, 
GHG<INF>i</INF> equals 1 for CH<INF>4</INF> and 0 for 
CO<INF>2</INF>; and for natural gas distribution, GHG<INF>i</INF> 
equals 1 for CH<INF>4</INF> and 1.1 x 10 
<SUP>-2</SUP>CO<INF>2</INF>.
T<INF>e</INF> = Average estimated time that each emission source 
type associated with the equipment leak emission was operational in 
the calendar year, in hours, using engineering estimate based on 
best available data.
T<INF>w,avg</INF> = Average estimated time that each meter/regulator 
run was operational in the calendar year, in hours per meter/
regulator run, using engineering estimate based on best available 
data.

    (1) Calculate both CH<INF>4</INF> and CO<INF>2</INF> mass emissions 
from volumetric emissions using calculations in paragraph (v) of this 
section.
    (2) Onshore petroleum and natural gas production facilities must 
use the appropriate default whole gas population emission factors 
listed in Table W-1A of this subpart. Major equipment and components 
associated with gas wells are considered gas service components in 
reference to Table W-1A of this subpart and major natural gas equipment 
in reference to Table W-1B of this subpart. Major equipment and 
components associated with crude oil wells are considered crude service 
components in reference to Table W-1A of this subpart and major crude 
oil equipment in reference to Table W-1C of this subpart. Where 
facilities conduct EOR operations the emissions factor listed in Table 
W-1A of this subpart shall be used to estimate all streams of gases, 
including recycle CO<INF>2</INF> stream. The component count can be 
determined using either of the calculation methods described in this 
paragraph (r)(2). The same calculation method must be used for the 
entire calendar year.
    (i) Component Count Method 1. For all onshore petroleum and natural 
gas production operations in the facility perform the following 
activities:
    (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.
    (B) Multiply major equipment counts by the average component counts 
listed in Table W-1B and W-1C of this subpart for onshore natural gas 
production and onshore oil production, respectively. Use the 
appropriate factor in Table W-1A of this subpart for operations in 
Eastern and Western U.S. according to the mapping in Table W-1D of this 
subpart.
    (ii) Component Count Method 2. Count each component individually 
for the facility. Use the appropriate factor in Table W-1A of this 
subpart for operations in Eastern and Western U.S. according to the 
mapping in Table W-1D of this subpart.
    (3) Underground natural gas storage facilities must use the 
appropriate default total hydrocarbon population emission factors for 
storage wellheads in gas service listed in Table W-4 of this subpart.
    (4) LNG storage facilities must use the appropriate default methane 
population emission factor for LNG storage compressors in gas service 
listed in Table W-5 of this subpart.
    (5) LNG import and export facilities must use the appropriate 
default methane population emission factor for LNG terminal compressors 
in gas

[[Page 70408]]

service listed in Table W-6 of this subpart.
    (6) Natural gas distribution facilities must use the appropriate 
methane emission factors as described in paragraphs (r)(6)(i) and (ii) 
of this section.
    (i) Below grade metering-regulating stations, distribution mains, 
and distribution services must use the appropriate default methane 
population emission factors listed in Table W-7 of this subpart. Below 
grade transmission-distribution transfer stations must use the emission 
factor for below grade metering-regulating stations.
    (ii) Above grade metering-regulating stations that are not above 
grade transmission-distribution transfer stations must use the meter/
regulator run population emission factor calculated in Equation W-31. 
Natural gas distribution facilities that do not have above grade 
transmission-distribution transfer stations are not required to 
calculate emissions for above grade metering-regulating stations and 
are not required to report GHG emissions in Sec.  98.236(r)(2)(v).
    (s) * * *
    (2) Offshore production facilities that are not under BOEMRE 
jurisdiction must use the most recent monitoring methods and 
calculation methods published by BOEMRE referenced in 30 CFR 250.302 
through 250.304 to calculate and report annual emissions (GOADS).
    (i) For any calendar year that does not overlap with the most 
recent BOEMRE emissions study publication, you may report the most 
recently reported emissions data submitted to demonstrate compliance 
with this subpart of part 98, with emissions adjusted based on the 
operating time for the facility relative to operating time in the 
previous reporting period.
* * * * *
    (3) If BOEMRE discontinues or delays their data collection effort 
by more than 4 years, then offshore reporters shall once in every 4 
years use the most recent BOEMRE data collection and emissions 
estimation methods to estimate emissions. These emission estimates 
would be used to report emissions from the facility sources as required 
in paragraph (s)(1)(i) of this section.
    (4) For either first or subsequent year reporting, offshore 
facilities either within or outside of BOEMRE jurisdiction that were 
not covered in the previous BOEMRE data collection cycle must use the 
most recent BOEMRE data collection and emissions estimation methods 
published by BOEMRE referenced in 30 CFR 250.302 through 250.304 to 
calculate and report emissions.
    (t) GHG volumetric emissions using actual conditions. If equation 
parameters in Sec.  98.233 are already determined at standard 
conditions as provided in the introductory text in Sec.  98.233, which 
results in volumetric emissions at standard conditions, then this 
paragraph does not apply. 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 actual natural gas emission temperature and pressure, 
and Equation W-33 of this section for conversions of E<INF>a,n</INF> or 
conversions of FR<INF>a</INF> (whether sub-sonic or sonic).
[GRAPHIC] [TIFF OMITTED] TR25NO14.050


Where:

E<INF>s,n</INF> = Natural gas volumetric emissions at standard 
temperature and pressure (STP) conditions in cubic feet, except 
E<INF>s,n</INF> equals FR<INF>s,p</INF> for each well p when 
calculating either subsonic or sonic flowrates under Sec.  
98.233(g).
E<INF>a,n</INF> = Natural gas volumetric emissions at actual 
conditions in cubic feet, except E<INF>a,n</INF> equals 
FR<INF>a,p</INF> for each well p when calculating either subsonic or 
sonic flowrates under Sec.  98.233(g).
T<INF>s</INF> = Temperature at standard conditions 
(60[emsp14][deg]F).
T<INF>a</INF> = Temperature at actual emission conditions ([deg]F).
P<INF>s</INF> = Absolute pressure at standard conditions (14.7 
psia).
P<INF>a</INF> = Absolute pressure at actual conditions (psia).
Z<INF>a</INF> = Compressibility factor at actual conditions for 
natural gas. You may use either a default compressibility factor of 
1, or a site-specific compressibility factor based on actual 
temperature and pressure conditions.

    (2) Calculate GHG volumetric emissions at standard conditions using 
actual GHG emissions temperature and pressure, and Equation W-34 of 
this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.051


Where:

E<INF>s,i</INF> = GHG i volumetric emissions at standard temperature 
and pressure (STP) conditions in cubic feet.
E<INF>a,i</INF> = GHG i volumetric emissions at actual conditions in 
cubic feet.
T<INF>s</INF> = Temperature at standard conditions 
(60[emsp14][deg]F).
T<INF>a</INF> = Temperature at actual emission conditions ([deg]F).
P<INF>s</INF> = Absolute pressure at standard conditions (14.7 
psia).
P<INF>a</INF> = Absolute pressure at actual conditions (psia).
Z<INF>a</INF> = Compressibility factor at actual conditions for GHG 
i.

    You may use either a default compressibility factor of 1, or a 
site-specific compressibility factor based on actual temperature and 
pressure conditions.
* * * * *
    (u) GHG volumetric emissions at standard conditions. Calculate GHG 
volumetric emissions at standard conditions as specified in paragraphs 
(u)(1) and (2) of this section.
* * * * *
    (2) * * *
    (iii) GHG mole fraction in transmission pipeline natural gas that 
passes through the facility for the onshore natural gas transmission 
compression industry segment. You may use either a default 95 percent 
methane and 1 percent carbon dioxide fraction for GHG mole fraction in 
natural gas or

[[Page 70409]]

site specific engineering estimates based on best available data.
    (iv) GHG mole fraction in natural gas stored in the underground 
natural gas storage industry segment. You may use either a default 95 
percent methane and 1 percent carbon dioxide fraction for GHG mole 
fraction in natural gas or site specific engineering estimates based on 
best available data.
    (v) GHG mole fraction in natural gas stored in the LNG storage 
industry segment. You may use either a default 95 percent methane and 1 
percent carbon dioxide fraction for GHG mole fraction in natural gas or 
site specific engineering estimates based on best available data.
    (vi) GHG mole fraction in natural gas stored in the LNG import and 
export industry segment. For export facilities that receive gas from 
transmission pipelines, you may use either a default 95 percent methane 
and 1 percent carbon dioxide fraction for GHG mole fraction in natural 
gas or site specific engineering estimates based on best available 
data.
    (vii) GHG mole fraction in local distribution pipeline natural gas 
that passes through the facility for natural gas distribution 
facilities. You may use either a default 95 percent methane and 1 
percent carbon dioxide fraction for GHG mole fraction in natural gas or 
site specific engineering estimates based on best available data.
    (v) GHG mass emissions. Calculate GHG mass emissions in metric tons 
by converting the GHG volumetric emissions at standard conditions into 
mass emissions using Equation W-36 of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.052


Where:

Mass<INF>i</INF> = GHG<INF>i</INF> (either CH<INF>4</INF>, 
CO<INF>2,</INF> or N<INF>2</INF>O) mass emissions in metric tons.
E<INF>s,i</INF> = GHG<INF>i</INF> (either CH<INF>4</INF>, 
CO<INF>2</INF>, or N<INF>2</INF>O) volumetric emissions at standard 
conditions, in cubic feet.
    [rho]<INF>i</INF> = Density of GHG<INF>i</INF>. Use 0.0526 kg/
ft\3\ for CO<INF>2</INF> and N<INF>2</INF>O, and 0.0192 kg/ft\3\ for 
CH<INF>4</INF> at 60[emsp14][deg]F and 14.7 psia.

    (w) EOR injection pump blowdown. Calculate CO<INF>2</INF> pump 
blowdown emissions from each EOR injection pump system as follows:
    (1) Calculate the total injection pump system volume in cubic feet 
(including pipelines, manifolds and vessels) between isolation valves.
* * * * *
    (3) Calculate the total annual CO<INF>2</INF> emissions from each 
EOR injection pump system using Equation W-37 of this section:
* * * * *
Mass<INF>CO2</INF> = Annual EOR injection pump system emissions in 
metric tons from blowdowns.
N = Number of blowdowns for the EOR injection pump system in the 
calendar year.
V<INF>v</INF> = Total volume in cubic feet of EOR injection pump 
system chambers (including pipelines, manifolds and vessels) between 
isolation valves.
* * * * *
    (x) EOR hydrocarbon liquids dissolved CO2. Calculate CO<INF>2</INF> 
emissions downstream of the storage tank from dissolved CO<INF>2</INF> 
in hydrocarbon liquids produced through EOR operations as follows:
    (1) Determine the amount of CO<INF>2</INF> retained in hydrocarbon 
liquids after flashing in tankage at STP conditions. Annual samples of 
hydrocarbon liquids downstream of the storage tank must be taken 
according to methods set forth in Sec.  98.234(b) to determine 
retention of CO<INF>2</INF> in hydrocarbon liquids immediately 
downstream of the storage tank. Use the annual analysis for the 
calendar year.
    (2) * * *
* * * * *
    S<INF>hl</INF> = Amount of CO<INF>2</INF> retained in 
hydrocarbon liquids downstream of the storage tank, in metric tons 
per barrel, under standard conditions.
* * * * *
    (z) * * *
    (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 
paragraph (z)(1)(i) of this section. If the fuel combusted 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 
method described in paragraph (z)(1)(i) of this section 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 Btu per standard cubic feet, calculate emissions 
according to paragraph (z)(2) of this section. If the fuel is field 
gas, process vent gas, or a blend containing field gas or process vent 
gas, calculate emissions according to paragraph (z)(2) of this section.
    (i) For fuels listed in Table C-1 or a blend containing one or more 
fuels listed in Table C-1, calculate CO<INF>2</INF>, CH<INF>4</INF>, 
and N<INF>2</INF>O emissions according to any Tier listed in subpart C 
of this part. You must follow all applicable calculation requirements 
for that tier listed in Sec.  98.33, any monitoring or QA/QC 
requirements listed for that tier in Sec.  98.34, any missing data 
procedures specified in Sec.  98.35, and any recordkeeping requirements 
specified in Sec.  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 Sec.  98.236(z) and not according to 
the reporting requirements specified in subpart C of this part.
    (2) * * *
    (iii) * * *
* * * * *
V<INF>a</INF> = Volume of gas sent to combustion unit in actual 
cubic feet, during the year.
Y<INF>CO2</INF> = Mole fraction of CO<INF>2</INF> constituent in gas 
sent to combustion unit.
* * * * *
Y<INF>j</INF> = Mole fraction of gas hydrocarbon constituents j 
(such as methane, ethane, propane, butane, and pentanes plus) in gas 
sent to combustion unit.
* * * * *
Y<INF>CH4</INF> = Mole fraction of methane constituent in gas sent 
to combustion unit.
* * * * *
    (vi) * * *
    [GRAPHIC] [TIFF OMITTED] TR25NO14.053
    

[[Page 70410]]


* * * * *
Mass<INF>N2O</INF> = Annual N<INF>2</INF>O emissions from the 
combustion of a particular type of fuel (metric tons).
Fuel = Annual mass or volume of the fuel combusted (mass or volume 
per year, choose appropriately to be consistent with the units of 
HHV).
HHV = Higher heating value of fuel, mmBtu/unit of fuel (in units 
consistent with the fuel quantity combusted). For field gas or 
process vent gas, you may use either a default higher heating value 
of 1.235 x 10<SUP>-3</SUP> mmBtu/scf or a site-specific higher 
heating value. For natural gas that is not of pipeline quality or 
that has a high heat value less than 950 Btu per standard cubic 
foot, use a site-specific higher heating value.
* * * * *

0
6. Section 98.234 is amended by:
0
a. Revising paragraphs (a) introductory text, (d)(1), and (f);
0
b. Removing and reserving paragraph (g); and
0
c. Adding paragraph (h).
    The revisions and additions read as follows:


Sec.  98.234  Monitoring and QA/QC requirements.

* * * * *
    (a) You must use any of the methods described as follows in this 
paragraph to conduct leak detection(s) of equipment leaks and through-
valve leakage from all source types listed in Sec.  98.233(k), (o), (p) 
and (q) that occur during a calendar year.
* * * * *
    (d) * * *
    (1) A technician following manufacturer instructions shall conduct 
measurements, including equipment manufacturer operating procedures and 
measurement methods relevant to using a high volume sampler, including 
positioning the instrument for complete capture of the equipment leak 
without creating backpressure on the source.
* * * * *
    (f) Special reporting provisions for best available monitoring 
methods in reporting year 2015--(1) Best available monitoring methods. 
From January 1, 2015 to March 31, 2015, for a facility subject to this 
subpart, you must use the calculation methodologies and equations in 
Sec.  98.233 ``Calculating GHG Emissions'', but you may use the best 
available monitoring method for any parameter for which it is not 
reasonably feasible to acquire, install, and operate a required piece 
of monitoring equipment by January 1, 2015 as specified in paragraphs 
(f)(2) and (3) of this section. Starting no later than April 1, 2015, 
you must discontinue using best available methods and begin following 
all applicable monitoring and QA/QC requirements of this part, except 
as provided in paragraph (f)(4) of this section. Best available 
monitoring methods means any of the following methods:
    (i) Monitoring methods currently used by the facility that do not 
meet the specifications of this subpart.
    (ii) Supplier data.
    (iii) Engineering calculations.
    (iv) Other company records.
    (2) Best available monitoring methods for well-related measurement 
data. You may use best available monitoring methods for well-related 
measurement data identified in paragraphs (f)(2)(i) and (ii) of this 
section that cannot reasonably be measured according to the monitoring 
and QA/QC requirements of this subpart.
    (i) If Calculation Method 1 for liquids unloading in Sec.  
98.233(f)(1) was used in calendar year 2014 and will be used again in 
calendar year 2015, the vented natural gas flow rate for any well in a 
unique tubing diameter group and pressure group combination that has 
not been previously measured.
    (ii) If using Equation W-10A of this subpart to determine natural 
gas emissions from completions and workovers for representative wells, 
the initial and average flowback rates (when using Calculation Method 1 
in Sec.  98.233(g)(1)(i)) or pressures upstream and downstream of the 
choke (when using Calculation Method 2 in Sec.  98.233(g)(1)(ii)) for 
any well in a well type combination that has not been previously 
measured.
    (3) Best available monitoring methods for emissions measurement. 
You may use best available monitoring methods for sources listed in 
paragraphs (f)(3)(i) and (ii) of this section if the required 
measurement data cannot reasonably be obtained according to the 
monitoring and QA/QC requirements of this part.
    (i) Centrifugal compressor as found measurements of manifolded 
emissions from groups of centrifugal compressor sources according to 
Sec.  98.233(o)(4) and (5), in onshore natural gas processing, onshore 
natural gas transmission compression, underground natural gas storage, 
LNG storage, and LNG import and export equipment as specified in Sec.  
98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2).
    (ii) Reciprocating compressor as found measurements of manifolded 
emissions from groups of reciprocating compressor sources according to 
Sec.  98.233(p)(4) and (5), in onshore natural gas processing, onshore 
natural gas transmission compression, underground natural gas storage, 
LNG storage, and LNG import and export equipment as specified in Sec.  
98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1).
    (4) Requests for extension of the use of best available monitoring 
methods beyond March 31, 2015. You may submit a request to the 
Administrator to use one or more best available monitoring methods for 
sources listed in paragraphs (f)(2) and (3) of this section beyond 
March 31, 2015.
    (i) Timing of request. The extension request must be submitted to 
EPA no later than January 31, 2015.
    (ii) Content of request. Requests must contain the following 
information:
    (A) A list of specific source types and parameters for which you 
are seeking use of best available monitoring methods.
    (B) For each specific source type for which you are requesting use 
of best available monitoring methods, a description of the reasons that 
the needed equipment could not be obtained and installed before April 
1, 2015.
    (C) A description of the specific actions you will take to obtain 
and install the equipment as soon as reasonably feasible and the 
expected date by which the equipment will be installed and operating.
    (iii) Approval criteria. To obtain approval to use best available 
monitoring methods after March 31, 2015, you must submit a request 
demonstrating to the Administrator's satisfaction that it is not 
reasonably feasible to acquire, install, and operate a required piece 
of monitoring equipment by April 1, 2015. The use of best available 
methods under paragraph (f) of this section will not be approved beyond 
December 31, 2015.
* * * * *
    (h) For well venting for liquids unloading, if a monitoring period 
other than the full calendar year is used to determine the cumulative 
amount of time in hours of venting for each well (the term 
``T<INF>p</INF>'' in Equation W-7A and W-7B of Sec.  98.233) or the 
number of unloading events per well (the term ``V<INF>p</INF>'' in 
Equations W-8 and W-9 of Sec.  98.233), then the monitoring period must 
begin before February 1 of the reporting year and must not end before 
December 1 of the reporting year. The end of one monitoring period must 
immediately precede the start of the next monitoring period for the 
next reporting year. All production days must be monitored and all 
venting accounted for.

0
7. Section 98.235 is revised to read as follows:

[[Page 70411]]

Sec.  98.235  Procedures for estimating missing data.

    Except as specified in Sec.  98.233, whenever a value of a 
parameter is unavailable for a GHG emission calculation required by 
this subpart (including, but not limited to, if a measuring device 
malfunctions during unit operation or activity data are not collected), 
you must follow the procedures specified in paragraphs (a) through (i) 
of this section, as applicable.
    (a) For stationary and portable combustion sources that use the 
calculation methods of subpart C of this part, you must use the missing 
data procedures in subpart C of this part.
    (b) For each missing value of a parameter that should have been 
measured quarterly or more frequently using equipment including, but 
not limited to, a continuous flow meter, composition analyzer, 
thermocouple, or pressure gauge, you must substitute the arithmetic 
average of the quality-assured values of that parameter immediately 
preceding and immediately following the missing data incident. If the 
``after'' value is not obtained by the end of the reporting year, you 
may use the ``before'' value for the missing data substitution. If, for 
a particular parameter, no quality-assured data are available prior to 
the missing data incident, you must use the first quality-assured value 
obtained after the missing data period as the substitute data value. A 
value is quality-assured according to the procedures specified in Sec.  
98.234.
    (c) For each missing value of a parameter that should have been 
measured annually, you must repeat the estimation or measurement 
activity for those sources as soon as possible, including in the 
subsequent calendar year if missing data are not discovered until after 
December 31 of the year in which data are collected, until valid data 
for reporting are obtained. Data developed and/or collected in a 
subsequent calendar year to substitute for missing data cannot be used 
for that subsequent year's emissions estimation. Where missing data 
procedures are used for the previous year, at least 30 days must 
separate emissions estimation or measurements for the previous year and 
emissions estimation or measurements for the current year of data 
collection.
    (d) For each missing value of a parameter that should have been 
measured biannually (every two years), you must conduct the estimation 
or measurement activity for those sources as soon as possible in the 
subsequent calendar year if the estimation or measurement was not made 
in the appropriate year (first year of data collection and every two 
years thereafter), until valid data for reporting are obtained. Data 
developed and/or collected in a subsequent calendar year to substitute 
for missing data cannot be used to alternate or postpone subsequent 
biannual emissions estimations or measurements.
    (e) For the first 6 months of required data collection, facilities 
that become newly subject to this subpart W may use best engineering 
estimates for any data that cannot reasonably be measured or obtained 
according to the requirements of this subpart.
    (f) For the first 6 months of required data collection, facilities 
that are currently subject to this subpart W and that acquire new 
sources from another facility that were not previously subject to this 
subpart W may use best engineering estimates for any data related to 
those newly acquired sources that cannot reasonably be measured or 
obtained according to the requirements of this subpart.
    (g) Unless addressed in another paragraph of this section, for each 
missing value of any activity data, you must substitute data value(s) 
using the best available estimate(s) of the parameter(s), based on all 
applicable and available process or other data (including, but not 
limited to, processing rates, operating hours).
    (h) You must report information for all measured and substitute 
values of a parameter, and the procedures used to substitute an 
unavailable value of a parameter per the requirements in Sec.  
98.236(bb).
    (i) You must follow recordkeeping requirements listed in Sec.  
98.237(f).

0
8. Section 98.236 is revised to read as follows:


Sec.  98.236  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain reported emissions and related information 
as specified in this section. Reporters that use a flow or volume 
measurement system that corrects to standard conditions as provided in 
the introductory text in Sec.  98.233 for data elements that are 
otherwise required to be determined at actual conditions, report gas 
volumes at standard conditions rather the gas volumes at actual 
conditions and report the standard temperature and pressure used by the 
measurement system rather than the actual temperature and pressure.
    (a) The annual report must include the information specified in 
paragraphs (a)(1) through (8) of this section for each applicable 
industry segment. The annual report must also include annual emissions 
totals, in metric tons of each GHG, for each applicable industry 
segment listed in paragraphs (a)(1) through (8) of this section, and 
each applicable emission source listed in paragraphs (b) through (z) of 
this section.
    (1) Onshore petroleum and natural gas production. For the 
equipment/activities specified in paragraphs (a)(1)(i) through (xvii) 
of this section, report the information specified in the applicable 
paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified 
in paragraph (b) of this section.
    (ii) Natural gas driven pneumatic pumps. Report the information 
specified in paragraph (c) of this section.
    (iii) Acid gas removal units. Report the information specified in 
paragraph (d) of this section.
    (iv) Dehydrators. Report the information specified in paragraph (e) 
of this section.
    (v) Liquids unloading. Report the information specified in 
paragraph (f) of this section.
    (vi) Completions and workovers with hydraulic fracturing. Report 
the information specified in paragraph (g) of this section.
    (vii) Completions and workovers without hydraulic fracturing. 
Report the information specified in paragraph (h) of this section.
    (viii) Onshore production storage tanks. Report the information 
specified in paragraph (j) of this section.
    (ix) Well testing. Report the information specified in paragraph 
(l) of this section.
    (x) Associated natural gas. Report the information specified in 
paragraph (m) of this section.
    (xi) Flare stacks. Report the information specified in paragraph 
(n) of this section.
    (xii) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (xiii) Reciprocating compressors. Report the information specified 
in paragraph (p) of this section.
    (xiv) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (xv) EOR injection pumps. Report the information specified in 
paragraph (w) of this section.
    (xvi) EOR hydrocarbon liquids. Report the information specified in 
paragraph (x) of this section.
    (xvii) Combustion equipment. Report the information specified in 
paragraph (z) of this section.
    (2) Offshore petroleum and natural gas production. Report the 
information specified in paragraph (s) of this section.
    (3) Onshore natural gas processing. For the equipment/activities 
specified

[[Page 70412]]

in paragraphs (a)(3)(i) through (vii) of this section, report the 
information specified in the applicable paragraphs of this section.
    (i) Acid gas removal units. Report the information specified in 
paragraph (d) of this section.
    (ii) Dehydrators. Report the information specified in paragraph (e) 
of this section.
    (iii) Blowdown vent stacks. Report the information specified in 
paragraph (i) of this section.
    (iv) Flare stacks. Report the information specified in paragraph 
(n) of this section.
    (v) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (vi) Reciprocating compressors. Report the information specified in 
paragraph (p) of this section.
    (vii) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (4) Onshore natural gas transmission compression. For the 
equipment/activities specified in paragraphs (a)(4)(i) through (vii) of 
this section, report the information specified in the applicable 
paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified 
in paragraph (b) of this section.
    (ii) Blowdown vent stacks. Report the information specified in 
paragraph (i) of this section.
    (iii) Transmission storage tanks. Report the information specified 
in paragraph (k) of this section.
    (iv) Flare stacks. Report the information specified in paragraph 
(n) of this section.
    (v) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (vi) Reciprocating compressors. Report the information specified in 
paragraph (p) of this section.
    (vii) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (5) Underground natural gas storage. For the equipment/activities 
specified in paragraphs (a)(5)(i) through (vi) of this section, report 
the information specified in the applicable paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified 
in paragraph (b) of this section.
    (ii) Flare stacks. Report the information specified in paragraph 
(n) of this section.
    (iii) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (iv) Reciprocating compressors. Report the information specified in 
paragraph (p) of this section.
    (v) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (vi) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (6) LNG storage. For the equipment/activities specified in 
paragraphs (a)(6)(i) through (v) of this section, report the 
information specified in the applicable paragraphs of this section.
    (i) Flare stacks. Report the information specified in paragraph (n) 
of this section.
    (ii) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (iii) Reciprocating compressors. Report the information specified 
in paragraph (p) of this section.
    (iv) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (v) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (7) LNG import and export equipment. For the equipment/activities 
specified in paragraphs (a)(7)(i) through (vi) of this section, report 
the information specified in the applicable paragraphs of this section.
    (i) Blowdown vent stacks. Report the information specified in 
paragraph (i) of this section.
    (ii) Flare stacks. Report the information specified in paragraph 
(n) of this section.
    (iii) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (iv) Reciprocating compressors. Report the information specified in 
paragraph (p) of this section.
    (v) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (vi) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (8) Natural gas distribution. For the equipment/activities 
specified in paragraphs (a)(8)(i) through (iii) of this section, report 
the information specified in the applicable paragraphs of this section.
    (i) Combustion equipment. Report the information specified in 
paragraph (z) of this section.
    (ii) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (iii) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (b) Natural gas pneumatic devices. You must indicate whether the 
facility contains the following types of equipment: Continuous high 
bleed natural gas pneumatic devices, continuous low bleed natural gas 
pneumatic devices, and intermittent bleed natural gas pneumatic 
devices. If the facility contains any continuous high bleed natural gas 
pneumatic devices, continuous low bleed natural gas pneumatic devices, 
or intermittent bleed natural gas pneumatic devices, then you must 
report the information specified in paragraphs (b)(1) through (b)(4) of 
this section.
    (1) The number of natural gas pneumatic devices as specified in 
paragraphs (b)(1)(i) and (ii) of this section.
    (i) The total number of devices of each type, determined according 
to Sec.  98.233(a)(1) and (2).
    (ii) If the reported value in paragraph (b)(1)(i) of this section 
is an estimated value determined according to Sec.  98.233(a)(2), then 
you must report the information specified in paragraphs (b)(1)(ii)(A) 
through (C) of this section.
    (A) The number of devices of each type reported in paragraph 
(b)(1)(i) of this section that are counted.
    (B) The number of devices of each type reported in paragraph 
(b)(1)(i) of this section that are estimated (not counted).
    (C) Whether the calendar year is the first calendar year of 
reporting or the second calendar year of reporting.
    (2) For each type of pneumatic device, the estimated average number 
of hours in the calendar year that the natural gas pneumatic devices 
reported in paragraph (b)(1)(i) of this section were operating in the 
calendar year (``T<INF>t</INF>'' in Equation W-1 of this subpart).
    (3) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>, 
for the natural gas pneumatic devices combined, calculated using 
Equation W-1 of this subpart and Sec.  98.233(a)(4), and reported in 
paragraph (b)(1)(i) of this section.
    (4) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
for the natural gas pneumatic devices combined, calculated using 
Equation W-1 of this subpart and Sec.  98.233(a)(4), and reported in 
paragraph (b)(1)(i) of this section.
    (c) Natural gas driven pneumatic pumps. You must indicate whether 
the facility has any natural gas driven pneumatic pumps. If the 
facility contains any natural gas driven pneumatic pumps, then you must 
report the information specified in paragraphs (c)(1) through (4) of 
this section.
    (1) Count of natural gas driven pneumatic pumps.
    (2) Average estimated number of hours in the calendar year the 
pumps were operational (``T'' in Equation W-2 of this subpart).

[[Page 70413]]

    (3) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>, 
for all natural gas driven pneumatic pumps combined, calculated 
according to Sec.  98.233(c)(1) and (2).
    (4) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
for all natural gas driven pneumatic pumps combined, calculated 
according to Sec.  98.233(c)(1) and (2).
    (d) Acid gas removal units. You must indicate whether your facility 
has any acid gas removal units that vent directly to the atmosphere, to 
a flare or engine, or to a sulfur recovery plant. If your facility 
contains any acid gas removal units that vent directly to the 
atmosphere, to a flare or engine, or to a sulfur recovery plant, then 
you must report the information specified in paragraphs (d)(1) and (2) 
of this section.
    (1) You must report the information specified in paragraphs 
(d)(1)(i) through (vi) of this section for each acid gas removal unit.
    (i) A unique name or ID number for the acid gas removal unit. For 
the onshore petroleum and natural gas production industry segment, a 
different name or ID may be used for a single acid gas removal unit for 
each location it operates at in a given year.
    (ii) Total feed rate entering the acid gas removal unit, using a 
meter or engineering estimate based on process knowledge or best 
available data, in million cubic feet per year.
    (iii) The calculation method used to calculate CO<INF>2</INF> 
emissions from the acid gas removal unit, as specified in Sec.  
98.233(d).
    (iv) Whether any CO<INF>2</INF> emissions from the acid gas removal 
unit are recovered and transferred outside the facility, as specified 
in Sec.  98.233(d)(11). If any CO<INF>2</INF> emissions from the acid 
gas removal unit were recovered and transferred outside the facility, 
then you must report the annual quantity of CO<INF>2</INF>, in metric 
tons CO<INF>2,</INF> that was recovered and transferred outside the 
facility under subpart PP of this part.
    (v) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>, 
from the acid gas removal unit, calculated using any one of the 
calculation methods specified in Sec.  98.233(d) and as specified in 
Sec.  98.233(d)(10) and (11).
    (vi) Sub-basin ID that best represents the wells supplying gas to 
the unit (for the onshore petroleum and natural gas production industry 
segment only).
    (2) You must report information specified in paragraphs (d)(2)(i) 
through (iii) of this section, applicable to the calculation method 
reported in paragraph (d)(1)(iii) of this section, for each acid gas 
removal unit.
    (i) If you used Calculation Method 1 or Calculation Method 2 as 
specified in Sec.  98.233(d) to calculate CO<INF>2</INF> emissions from 
the acid gas removal unit, then you must report the information 
specified in paragraphs (d)(2)(i)(A) and (B) of this section.
    (A) Annual average volumetric fraction of CO<INF>2</INF> in the 
vent gas exiting the acid gas removal unit.
    (B) Annual volume of gas vented from the acid gas removal unit, in 
cubic feet.
    (ii) If you used Calculation Method 3 as specified in Sec.  
98.233(d) to calculate CO<INF>2</INF> emissions from the acid gas 
removal unit, then you must report the information specified in 
paragraphs (d)(2)(ii)(A) through (D) of this section.
    (A) Indicate which equation was used (Equation W-4A or W-4B).
    (B) Annual average volumetric fraction of CO<INF>2</INF> in the 
natural gas flowing out of the acid gas removal unit, as specified in 
Equation W-4A or Equation W-4B of this subpart.
    (C) Annual average volumetric fraction of CO<INF>2</INF> content in 
natural gas flowing into the acid gas removal unit, as specified in 
Equation W-4A or Equation W-4B of this subpart.
    (D) The natural gas flow rate used, as specified in Equation W-4A 
of this subpart, reported as either total annual volume of natural gas 
flow into the acid gas removal unit in cubic feet at actual conditions; 
or total annual volume of natural gas flow out of the acid gas removal 
unit, as specified in Equation W-4B of this subpart, in cubic feet at 
actual conditions.
    (iii) If you used Calculation Method 4 as specified in Sec.  
98.233(d) to calculate CO<INF>2</INF> emissions from the acid gas 
removal unit, then you must report the information specified in 
paragraphs (d)(2)(iii)(A) through (L) of this section, as applicable to 
the simulation software package used.
    (A) The name of the simulation software package used.
    (B) Natural gas feed temperature, in degrees Fahrenheit.
    (C) Natural gas feed pressure, in pounds per square inch.
    (D) Natural gas flow rate, in standard cubic feet per minute.
    (E) Acid gas content of the feed natural gas, in mole percent.
    (F) Acid gas content of the outlet natural gas, in mole percent.
    (G) Unit operating hours, excluding downtime for maintenance or 
standby, in hours per year.
    (H) Exit temperature of the natural gas, in degrees Fahrenheit.
    (I) Solvent pressure, in pounds per square inch.
    (J) Solvent temperature, in degrees Fahrenheit.
    (K) Solvent circulation rate, in gallons per minute.
    (L) Solvent weight, in pounds per gallon.
    (e) Dehydrators. You must indicate whether your facility contains 
any of the following equipment: Glycol dehydrators with an annual 
average daily natural gas throughput greater than or equal to 0.4 
million standard cubic feet per day, glycol dehydrators with an annual 
average daily natural gas throughput less than 0.4 million standard 
cubic feet per day, and dehydrators that use desiccant. If your 
facility contains any of the equipment listed in this paragraph (e), 
then you must report the applicable information in paragraphs (e)(1) 
through (3).
    (1) For each glycol dehydrator that has an annual average daily 
natural gas throughput greater than or equal to 0.4 million standard 
cubic feet per day (as specified in Sec.  98.233(e)(1)), you must 
report the information specified in paragraphs (e)(1)(i) through 
(xviii) of this section for the dehydrator.
    (i) A unique name or ID number for the dehydrator. For the onshore 
petroleum and natural gas production industry segment, a different name 
or ID may be used for a single dehydrator for each location it operates 
at in a given year.
    (ii) Dehydrator feed natural gas flow rate, in million standard 
cubic feet per day, determined by engineering estimate based on best 
available data.
    (iii) Dehydrator feed natural gas water content, in pounds per 
million standard cubic feet.
    (iv) Dehydrator outlet natural gas water content, in pounds per 
million standard cubic feet.
    (v) Dehydrator absorbent circulation pump type (e.g., natural gas 
pneumatic, air pneumatic, or electric).
    (vi) Dehydrator absorbent circulation rate, in gallons per minute.
    (vii) Type of absorbent (e.g., triethylene glycol (TEG), diethylene 
glycol (DEG), or ethylene glycol (EG)).
    (viii) Whether stripper gas is used in dehydrator.
    (ix) Whether a flash tank separator is used in dehydrator.
    (x) Total time the dehydrator is operating, in hours.
    (xi) Temperature of the wet natural gas, in degrees Fahrenheit.
    (xii) Pressure of the wet natural gas, in pounds per square inch 
gauge.
    (xiii) Mole fraction of CH<INF>4</INF> in wet natural gas.
    (xiv) Mole fraction of CO<INF>2</INF> in wet natural gas.
    (xv) Whether any dehydrator emissions are vented to a vapor 
recovery device.
    (xvi) Whether any dehydrator emissions are vented to a flare or 
regenerator firebox/fire tubes. If any emissions are vented to a flare 
or

[[Page 70414]]

regenerator firebox/fire tubes, report the information specified in 
paragraphs (e)(1)(xvi)(A) through (C) of this section for these 
emissions from the dehydrator.
    (A) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>, 
for the dehydrator, calculated according to Sec.  98.233(e)(6).
    (B) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
for the dehydrator, calculated according to Sec.  98.233(e)(6).
    (C) Annual N<INF>2</INF>O emissions, in metric tons N<INF>2</INF>O, 
for the dehydrator, calculated according to Sec.  98.233(e)(6).
    (xvii) Whether any dehydrator emissions are vented to the 
atmosphere without being routed to a flare or regenerator firebox/fire 
tubes. If any emissions are not routed to a flare or regenerator 
firebox/fire tubes, then you must report the information specified in 
paragraphs (e)(1)(xvii)(A) and (B) of this section for those emissions 
from the dehydrator.
    (A) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>, 
for the dehydrator when not venting to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(1), and, if 
applicable, (e)(5).
    (B) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
for the dehydrator when not venting to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(1) and, if 
applicable, (e)(5).
    (xviii) Sub-basin ID that best represents the wells supplying gas 
to the dehydrator (for the onshore petroleum and natural gas production 
industry segment only).
    (2) For glycol dehydrators with an annual average daily natural gas 
throughput less than 0.4 million standard cubic feet per day (as 
specified in Sec.  98.233(e)(2)), you must report the information 
specified in paragraphs (e)(2)(i) through (v) of this section for the 
entire facility.
    (i) The total number of dehydrators at the facility.
    (ii) Whether any dehydrator emissions were vented to a vapor 
recovery device. If any dehydrator emissions were vented to a vapor 
recovery device, then you must report the total number of dehydrators 
at the facility that vented to a vapor recovery device.
    (iii) Whether any dehydrator emissions were vented to a control 
device other than a vapor recovery device or a flare or regenerator 
firebox/fire tubes. If any dehydrator emissions were vented to a 
control device(s) other than a vapor recovery device or a flare or 
regenerator firebox/fire tubes, then you must specify the type of 
control device(s) and the total number of dehydrators at the facility 
that were vented to each type of control device.
    (iv) Whether any dehydrator emissions were vented to a flare or 
regenerator firebox/fire tubes. If any dehydrator emissions were vented 
to a flare or regenerator firebox/fire tubes, then you must report the 
information specified in paragraphs (e)(2)(iv)(A) through (D) of this 
section.
    (A) The total number of dehydrators venting to a flare or 
regenerator firebox/fire tubes.
    (B) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>, 
for the dehydrators reported in paragraph (e)(2)(iv)(A) of this 
section, calculated according to Sec.  98.233(e)(6).
    (C) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
for the dehydrators reported in paragraph (e)(2)(iv)(A) of this 
section, calculated according to Sec.  98.233(e)(6).
    (D) Annual N<INF>2</INF>O emissions, in metric tons N<INF>2</INF>O, 
for the dehydrators reported in paragraph (e)(2)(iv)(A) of this 
section, calculated according to Sec.  98.233(e)(6).
    (v) For dehydrator emissions that were not vented to a flare or 
regenerator firebox/fire tubes, report the information specified in 
paragraphs (e)(2)(v)(A) and (B) of this section.
    (A) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>, 
for emissions from all dehydrators reported in paragraph (e)(2)(i) of 
this section that were not vented to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(2), (e)(4), and, if 
applicable, (e)(5), where emissions are added together for all such 
dehydrators.
    (B) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
for emissions from all dehydrators reported in paragraph (e)(2)(i) of 
this section that were not vented to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(2), (e)(4), and, if 
applicable, (e)(5), where emissions are added together for all such 
dehydrators.
    (3) For dehydrators that use desiccant (as specified in Sec.  
98.233(e)(3)), you must report the information specified in paragraphs 
(e)(3)(i) through (iii) of this section for the entire facility.
    (i) The same information specified in paragraphs (e)(2)(i) through 
(iv) of this section for glycol dehydrators, and report the information 
under this paragraph for dehydrators that use desiccant.
    (ii) Annual CO<INF>2</INF> emissions, in metric tons 
CO<INF>2</INF>, for emissions from all desiccant dehydrators reported 
under paragraph (e)(3)(i) of this section that are not venting to a 
flare or regenerator firebox/fire tubes, calculated according to Sec.  
98.233(e)(3), (e)(4), and, if applicable, (e)(5), and summing for all 
such dehydrators.
    (iii) Annual CH<INF>4</INF> emissions, in metric tons 
CH<INF>4</INF>, for emissions from all desiccant dehydrators reported 
in paragraph (e)(3)(i) of this section that are not venting to a flare 
or regenerator firebox/fire tubes, calculated according to Sec.  
98.233(e)(3), (e)(4), and, if applicable, (e)(5), and summing for all 
such dehydrators.
    (f) Liquids unloading. You must indicate whether well venting for 
liquids unloading occurs at your facility, and if so, which methods (as 
specified in Sec.  98.233(f)) were used to calculate emissions. If your 
facility performs well venting for liquids unloading and uses 
Calculation Method 1, then you must report the information specified in 
paragraph (f)(1) of this section. If the facility performs liquids 
unloading and uses Calculation Method 2 or 3, then you must report the 
information specified in paragraph (f)(2) of this section.
    (1) For each sub-basin and well tubing diameter and pressure group 
for which you used Calculation Method 1 to calculate natural gas 
emissions from well venting for liquids unloading, report the 
information specified in paragraphs (f)(1)(i) through (xii) of this 
section. Report information separately for wells with plunger lifts and 
wells without plunger lifts.
    (i) Sub-basin ID.
    (ii) Well tubing diameter and pressure group ID.
    (iii) Plunger lift indicator.
    (iv) Count of wells vented to the atmosphere for the sub-basin/well 
tubing diameter and pressure group.
    (v) Percentage of wells for which the monitoring period used to 
determine the cumulative amount of time venting was not the full 
calendar year.
    (vi) Cumulative amount of time wells were vented (sum of 
``T<INF>p</INF>'' from Equation W-7A or W-7B of this subpart), in 
hours.
    (vii) Cumulative number of unloadings vented to the atmosphere for 
each well, aggregated across all wells in the sub-basin/well tubing 
diameter and pressure group.
    (viii) Annual natural gas emissions, in standard cubic feet, from 
well venting for liquids unloading, calculated according to Sec.  
98.233(f)(1).
    (ix) Annual CO<INF>2</INF> emissions, in metric tons 
CO<INF>2</INF>, from well venting for liquids unloading, calculated 
according to Sec.  98.233(f)(1) and (4).
    (x) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
from well venting for liquids unloading, calculated according to Sec.  
98.233(f)(1) and (4).
    (xi) For each well tubing diameter group and pressure group 
combination, you must report the information specified in paragraphs 
(f)(1)(xi)(A) through (E) of this section for each individual well not 
using a plunger lift that was tested during the year.
    (A) API Well Number of tested well.

[[Page 70415]]

    (B) Casing pressure, in pounds per square inch absolute.
    (C) Internal casing diameter, in inches.
    (D) Measured depth of the well, in feet.
    (E) Average flow rate of the well venting over the duration of the 
liquids unloading, in standard cubic feet per hour.
    (xii) For each well tubing diameter group and pressure group 
combination, you must report the information specified in paragraphs 
(f)(1)(xii)(A) through (E) of this section for each individual well 
using a plunger lift that was tested during the year.
    (A) API Well Number.
    (B) The tubing pressure, in pounds per square inch absolute.
    (C) The internal tubing diameter, in inches.
    (D) Measured depth of the well, in feet.
    (E) Average flow rate of the well venting over the duration of the 
liquids unloading, in standard cubic feet per hour.
    (2) For each sub-basin for which you used Calculation Method 2 or 3 
(as specified in Sec.  93.233(f)) to calculate natural gas emissions 
from well venting for liquids unloading, you must report the 
information in (f)(2)(i) through (x) of this section. Report 
information separately for each calculation method.
    (i) Sub-basin ID.
    (ii) Calculation method.
    (iii) Plunger lift indicator.
    (iv) Number of wells vented to the atmosphere.
    (v) Cumulative number of unloadings vented to the atmosphere for 
each well, aggregated across all wells.
    (vi) Annual natural gas emissions, in standard cubic feet, from 
well venting for liquids unloading, calculated according to Sec.  
98.233(f)(2) or (3), as applicable.
    (vii) Annual CO<INF>2</INF> emissions, in metric tons 
CO<INF>2</INF>, from well venting for liquids unloading, calculated 
according to Sec.  98.233(f)(2) or (3), as applicable, and Sec.  
98.233(f)(4).
    (viii) Annual CH<INF>4</INF> emissions, in metric tons 
CH<INF>4</INF>, from well venting for liquids unloading, calculated 
according to Sec.  98.233(f)(2) or (3), as applicable, and Sec.  
98.233(f)(4).
    (ix) For wells without plunger lifts, the average internal casing 
diameter, in inches.
    (x) For wells with plunger lifts, the average internal tubing 
diameter, in inches.
    (g) Completions and workovers with hydraulic fracturing. You must 
indicate whether your facility had any gas well completions or 
workovers with hydraulic fracturing during the calendar year. If your 
facility had gas well completions or workovers with hydraulic 
fracturing during the calendar year, then you must report information 
specified in paragraphs (g)(1) through (10) of this section, for each 
sub-basin and well type combination. Report information separately for 
completions and workovers.
    (1) Sub-basin ID.
    (2) Well type combination.
    (3) Number of completions or workovers in the sub-basin and well 
type combination category.
    (4) Calculation method used.
    (5) If you used Equation W-10A to calculate annual volumetric total 
gas emissions, then you must report the information specified in 
paragraphs (g)(5)(i) and (ii) of this section.
    (i) Cumulative gas flowback time, in hours, from when gas is first 
detected until sufficient quantities are present to enable separation, 
and the cumulative flowback time, in hours, after sufficient quantities 
of gas are present to enable separation (sum of ``T<INF>p,i</INF>'' and 
sum of ``T<INF>p,s</INF>'' values used in Equation W-10A). You may 
delay the reporting of this data element if you indicate in the annual 
report that wildcat wells and/or delineation wells are the only wells 
included in this number. If you elect to delay reporting of this data 
element, you must report by the date specified in Sec.  98.236(cc) the 
total number of hours of flowback from all wells during completions or 
workovers and the API Well Number(s) for the well(s) included in the 
number.
    (ii) For the measured well(s), the flowback rate, in standard cubic 
feet per hour (average of ``FR<INF>s,p</INF>'' values used in Equation 
W-12A). You may delay the reporting of this data element if you 
indicate in the annual report that wildcat wells and/or delineation 
wells are the only wells that can be used for the measurement. If you 
elect to delay reporting of this data element, you must report by the 
date specified in Sec.  98.236(cc) the measured flowback rate during 
well completion or workover and the API Well Number(s) for the well(s) 
included in the measurement.
    (6) If you used Equation W-10B to calculate annual volumetric total 
gas emissions, then you must report the information specified in 
paragraphs (g)(6)(i) and (ii) of this section.
    (i) Vented natural gas volume, in standard cubic feet, for each 
well in the sub-basin (``FV<INF>s,p</INF>'' in Equation W-10B).
    (ii) Flow rate at the beginning of the period of time when 
sufficient quantities of gas are present to enable separation, in 
standard cubic feet per hour, for each well in the sub-basin 
(``FR<INF>p,i</INF>'' in Equation W-10B).
    (7) Annual gas emissions, in standard cubic feet 
(``E<INF>s,n</INF>'' in Equation W-10A or W-10B).
    (8) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>.
    (9) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>.
    (10) If the well emissions were vented to a flare, then you must 
report the total N<INF>2</INF>O emissions, in metric tons 
N<INF>2</INF>O.
    (h) Completions and workovers without hydraulic fracturing. You 
must indicate whether the facility had any gas well completions without 
hydraulic fracturing or any gas well workovers without hydraulic 
fracturing, and if the activities occurred with or without flaring. If 
the facility had gas well completions or workovers without hydraulic 
fracturing, then you must report the information specified in 
paragraphs (h)(1) through (4) of this section, as applicable.
    (1) For each sub-basin with gas well completions without hydraulic 
fracturing and without flaring, report the information specified in 
paragraphs (h)(1)(i) through (vi) of this section.
    (i) Sub-basin ID.
    (ii) Number of well completions that vented gas directly to the 
atmosphere without flaring.
    (iii) Total number of hours that gas vented directly to the 
atmosphere during venting for all completions in the sub-basin category 
(the sum of all ``T<INF>p</INF>'' for completions that vented to the 
atmosphere as used in Equation W-13B).
    (iv) Average daily gas production rate for all completions without 
hydraulic fracturing in the sub-basin without flaring, in standard 
cubic feet per hour (average of all ``V<INF>p</INF>'' used in Equation 
W-13B). You may delay reporting of this data element if you indicate in 
the annual report that wildcat wells and/or delineation wells are the 
only wells that can be used for the measurement. If you elect to delay 
reporting of this data element, you must report by the date specified 
in Sec.  98.236(cc) the measured average daily gas production rate for 
all wells during completions and the API Well Number(s) for the well(s) 
included in the measurement.
    (v) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>, 
that resulted from completions venting gas directly to the atmosphere 
(``E<INF>s,p</INF>'' from Equation W-13B for completions that vented 
directly to the atmosphere, converted to mass emissions according to 
Sec.  98.233(h)(1)).
    (vi) Annual CH<INF>4</INF> emissions, in metric tons 
CH<INF>4</INF>, that resulted from completions venting gas directly to 
the atmosphere (``E<INF>s,p</INF>'' from Equation W-

[[Page 70416]]

13B for completions that vented directly to the atmosphere, converted 
to mass emissions according to Sec.  98.233(h)(1)).
    (2) For each sub-basin with gas well completions without hydraulic 
fracturing and with flaring, report the information specified in 
paragraphs (h)(2)(i) through (vii) of this section.
    (i) Sub-basin ID.
    (ii) Number of well completions that flared gas.
    (iii) Total number of hours that gas vented to a flare during 
venting for all completions in the sub-basin category (the sum of all 
``T<INF>p</INF>'' for completions that vented to a flare from Equation 
W-13B).
    (iv) Average daily gas production rate for all completions without 
hydraulic fracturing in the sub-basin with flaring, in standard cubic 
feet per hour (the average of all ``V<INF>p</INF>'' from Equation W-
13B). You may delay reporting of this data element if you indicate in 
the annual report that wildcat wells and/or delineation wells are the 
only wells that can be used for the measurement. If you elect to delay 
reporting of this data element, you must report by the date specified 
in Sec.  98.236(cc) the measured average daily gas production rate for 
all wells during completions and the API Well Number(s) for the well(s) 
included in the measurement.
    (v) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>, 
that resulted from completions that flared gas calculated according to 
Sec.  98.233(h)(2).
    (vi) Annual CH<INF>4</INF> emissions, in metric tons 
CH<INF>4</INF>, that resulted from completions that flared gas 
calculated according to Sec.  98.233(h)(2).
    (vii) Annual N<INF>2</INF>O emissions, in metric tons 
N<INF>2</INF>O, that resulted from completions that flared gas 
calculated according to Sec.  98.233(h)(2).
    (3) For each sub-basin with gas well workovers without hydraulic 
fracturing and without flaring, report the information specified in 
paragraphs (h)(3)(i) through (iv) of this section.
    (i) Sub-basin ID.
    (ii) Number of workovers that vented gas to the atmosphere without 
flaring.
    (iii) Annual CO<INF>2</INF> emissions, in metric tons 
CO<INF>2</INF> per year, that resulted from workovers venting gas 
directly to the atmosphere (``E<INF>s,wo</INF>'' in Equation W-13A for 
workovers that vented directly to the atmosphere, converted to mass 
emissions as specified in Sec.  98.233(h)(1)).
    (iv) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF> 
per year, that resulted from workovers venting gas directly to the 
atmosphere (``E<INF>s,wo</INF>'' in Equation W-13A for workovers that 
vented directly to the atmosphere, converted to mass emissions as 
specified in Sec.  98.233(h)(1)).
    (4) For each sub-basin with gas well workovers without hydraulic 
fracturing and with flaring, report the information specified in 
paragraphs (h)(4)(i) through (v) of this section.
    (i) Sub-basin ID.
    (ii) Number of workovers that flared gas.
    (iii) Annual CO<INF>2</INF> emissions, in metric tons 
CO<INF>2</INF> per year, that resulted from workovers that flared gas 
calculated as specified in Sec.  98.233(h)(2).
    (iv) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF> 
per year, that resulted from workovers that flared gas, calculated as 
specified in Sec.  98.233(h)(2).
    (v) Annual N<INF>2</INF>O emissions, in metric tons N<INF>2</INF>O 
per year, that resulted from workovers that flared gas calculated as 
specified in Sec.  98.233(h)(2).
    (i) Blowdown vent stacks. You must indicate whether your facility 
has blowdown vent stacks. If your facility has blowdown vent stacks, 
then you must report whether emissions were calculated by equipment or 
event type or by using flow meters or a combination of both. If you 
calculated emissions by equipment or event type for any blowdown vent 
stacks, then you must report the information specified in paragraph 
(i)(1) of this section considering, in aggregate, all blowdown vent 
stacks for which emissions were calculated by equipment or event type. 
If you calculated emissions using flow meters for any blowdown vent 
stacks, then you must report the information specified in paragraph 
(i)(2) of this section considering, in aggregate, all blowdown vent 
stacks for which emissions were calculated using flow meters.
    (1) Report by equipment or event type. If you calculated emissions 
from blowdown vent stacks by the seven categories listed in Sec.  
98.233(i)(2), then you must report the equipment or event types and the 
information specified in paragraphs (i)(1)(i) through (iii) of this 
section for each equipment or event type. If a blowdown event resulted 
in emissions from multiple equipment types, and the emissions cannot be 
apportioned to the different equipment types, then you may report the 
information in paragraphs (i)(1)(i) through (iii) of this section for 
the equipment type that represented the largest portion of the 
emissions for the blowdown event.
    (i) Total number of blowdowns in the calendar year for the 
equipment or event type (the sum of equation variable ``N'' from 
Equation W-14A or Equation W-14B of this subpart, for all unique 
physical volumes for the equipment or event type).
    (ii) Annual CO<INF>2</INF> emissions for the equipment or event 
type, in metric tons CO<INF>2</INF>, calculated according to Sec.  
98.233(i)(2)(iii).
    (iii) Annual CH<INF>4</INF> emissions for the equipment or event 
type, in metric tons CH<INF>4</INF>, calculated according to Sec.  
98.233(i)(2)(iii).
    (2) Report by flow meter. If you elect to calculate emissions from 
blowdown vent stacks by using a flow meter according to Sec.  
98.233(i)(3), then you must report the information specified in 
paragraphs (i)(2)(i) and (ii) of this section for the facility.
    (i) Annual CO<INF>2</INF> emissions from all blowdown vent stacks 
at the facility for which emissions were calculated using flow meters, 
in metric tons CO<INF>2</INF> (the sum of all CO<INF>2</INF> mass 
emission values calculated according to Sec.  98.233(i)(3), for all 
flow meters).
    (ii) Annual CH<INF>4</INF> emissions from all blowdown vent stacks 
at the facility for which emissions were calculated using flow meters, 
in metric tons CH<INF>4</INF>, (the sum of all CH<INF>4</INF> mass 
emission values calculated according to Sec.  98.233(i)(3), for all 
flow meters).
    (j) Onshore production storage tanks. You must indicate whether 
your facility sends produced oil to atmospheric tanks. If your facility 
sends produced oil to atmospheric tanks, then you must indicate which 
Calculation Method(s) you used to calculate GHG emissions, and you must 
report the information specified in paragraphs (j)(1) and (2) of this 
section as applicable. If you used Calculation Method 1 or Calculation 
Method 2, and any atmospheric tanks were observed to have 
malfunctioning dump valves during the calendar year, then you must 
indicate that dump valves were malfunctioning and you must report the 
information specified in paragraph (j)(3) of this section.
    (1) If you used Calculation Method 1 or Calculation Method 2 to 
calculate GHG emissions, then you must report the information specified 
in paragraphs (j)(1)(i) through (xiv) of this section for each sub-
basin and by calculation method.
    (i) Sub-basin ID.
    (ii) Calculation method used, and name of the software package used 
if using Calculation Method 1.
    (iii) The total annual oil volume from gas-liquid separators and 
direct from wells that is sent to applicable onshore production storage 
tanks, in barrels. You may delay reporting of this data element if you 
indicate in the annual report that wildcat wells and delineation wells 
are the only wells in the sub-basin with oil production greater than or 
equal to 10 barrels per day and flowing to gas-liquid separators or 
direct to storage tanks. If you elect to delay reporting of this data 
element, you must report by the date

[[Page 70417]]

specified in Sec.  98.236(cc) the total volume of oil from all wells 
and the API Well Number(s) for the well(s) included in this volume.
    (iv) The average gas-liquid separator temperature, in degrees 
Fahrenheit.
    (v) The average gas-liquid separator pressure, in pounds per square 
inch gauge.
    (vi) The average sales oil or stabilized oil API gravity, in 
degrees.
    (vii) The minimum and maximum concentration (mole fraction) of 
CO<INF>2</INF> in flash gas from onshore production storage tanks.
    (viii) The minimum and maximum concentration (mole fraction) of 
CH<INF>4</INF> in flash gas from onshore production storage tanks.
    (ix) The number of wells sending oil to gas-liquid separators or 
directly to atmospheric tanks.
    (x) The number of atmospheric tanks.
    (xi) An estimate of the number of atmospheric tanks, not on well-
pads, receiving your oil.
    (xii) If any emissions from the atmospheric tanks at your facility 
were controlled with vapor recovery systems, then you must report the 
information specified in paragraphs (j)(1)(xii)(A) through (E) of this 
section.
    (A) The number of atmospheric tanks that control emissions with 
vapor recovery systems.
    (B) Total CO<INF>2</INF> mass, in metric tons CO<INF>2</INF>, that 
was recovered during the calendar year using a vapor recovery system.
    (C) Total CH<INF>4</INF> mass, in metric tons CH<INF>4</INF>, that 
was recovered during the calendar year using a vapor recovery system.
    (D) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>, 
from atmospheric tanks equipped with vapor recovery systems.
    (E) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
from atmospheric tanks equipped with vapor recovery systems.
    (xiii) If any atmospheric tanks at your facility vented gas 
directly to the atmosphere without using a vapor recovery system or 
without flaring, then you must report the information specified in 
paragraphs (j)(1)(xiii)(A) through (C) of this section.
    (A) The number of atmospheric tanks that vented gas directly to the 
atmosphere without using a vapor recovery system or without flaring.
    (B) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>, 
that resulted from venting gas directly to the atmosphere.
    (C) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
that resulted from venting gas directly to the atmosphere.
    (xiv) If you controlled emissions from any atmospheric tanks at 
your facility with one or more flares, then you must report the 
information specified in paragraphs (j)(1)(xiv)(A) through (D) of this 
section.
    (A) The number of atmospheric tanks that controlled emissions with 
flares.
    (B) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>, 
from atmospheric tanks that controlled emissions with one or more 
flares.
    (C) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
from atmospheric tanks that controlled emissions with one or more 
flares.
    (D) Annual N<INF>2</INF>O emissions, in metric tons N<INF>2</INF>O, 
from atmospheric tanks that controlled emissions with one or more 
flares.
    (2) If you used Calculation Method 3 to calculate GHG emissions, 
then you must report the information specified in paragraphs (j)(2)(i) 
through (iii) of this section.
    (i) Report the information specified in paragraphs (j)(2)(i)(A) 
through (F) of this section, at the basin level, for atmospheric tanks 
where emissions were calculated using Calculation Method 3.
    (A) The total annual oil throughput that is sent to all atmospheric 
tanks in the basin, in barrels. You may delay reporting of this data 
element if you indicate in the annual report that wildcat wells and 
delineation wells are the only wells in the sub-basin with oil 
production less than 10 barrels per day and that send oil to 
atmospheric tanks. If you elect to delay reporting of this data 
element, you must report by the date specified in Sec.  98.236(cc) the 
total annual oil throughput from all wells and the API Well Number(s) 
for the well(s) included in this volume.
    (B) An estimate of the fraction of oil throughput reported in 
paragraph (j)(2)(i)(A) of this section sent to atmospheric tanks in the 
basin that controlled emissions with flares.
    (C) An estimate of the fraction of oil throughput reported in 
paragraph (j)(2)(i)(A) of this section sent to atmospheric tanks in the 
basin that controlled emissions with vapor recovery systems.
    (D) The number of atmospheric tanks in the basin.
    (E) The number of wells with gas-liquid separators (``Count'' from 
Equation W-15 of this subpart) in the basin.
    (F) The number of wells without gas-liquid separators (``Count'' 
from Equation W-15 of this subpart) in the basin.
    (ii) Report the information specified in paragraphs (j)(2)(ii)(A) 
through (D) of this section for each sub-basin with atmospheric tanks 
whose emissions were calculated using Calculation Method 3 and that did 
not control emissions with flares.
    (A) Sub-basin ID.
    (B) The number of atmospheric tanks in the sub-basin that did not 
control emissions with flares.
    (C) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>, 
from atmospheric tanks in the sub-basin that did not control emissions 
with flares, calculated using Equation W-15 of this subpart and 
adjusted for vapor recovery, if applicable.
    (D) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
from atmospheric tanks in the sub-basin that did not control emissions 
with flares, calculated using Equation W-15 of this subpart and 
adjusted for vapor recovery, if applicable.
    (iii) Report the information specified in paragraphs (j)(2)(iii)(A) 
through (E) of this section for each sub-basin with atmospheric tanks 
whose emissions were calculated using Calculation Method 3 and that 
controlled emissions with flares.
    (A) Sub-basin ID.
    (B) The number of atmospheric tanks in the sub-basin that 
controlled emissions with flares.
    (C) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>, 
from atmospheric tanks that controlled emissions with flares.
    (D) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
from atmospheric tanks that controlled emissions with flares.
    (E) Annual N<INF>2</INF>O emissions, in metric tons N<INF>2</INF>O, 
from atmospheric tanks that controlled emissions with flares.
    (3) If you used Calculation Method 1 or Calculation Method 2, and 
any gas-liquid separator liquid dump values did not close properly 
during the calendar year, then you must report the information 
specified in paragraphs (j)(3)(i) through (iv) of this section for each 
sub-basin.
    (i) The total number of gas-liquid separators whose liquid dump 
valves did not close properly during the calendar year.
    (ii) The total time the dump valves on gas-liquid separators did 
not close properly in the calendar year, in hours (sum of the 
``T<INF>n</INF>'' values used in Equation W-16 of this subpart).
    (iii) Annual CO<INF>2</INF> emissions, in metric tons 
CO<INF>2</INF>, that resulted from dump valves on gas-liquid separators 
not closing properly during the calendar year, calculated using 
Equation W-16 of this subpart.
    (iv) Annual CH<INF>4</INF> emissions, in metric tons 
CH<INF>4</INF>, that resulted from the dump valves on gas-liquid 
separators not closing properly during the calendar year, calculated 
using Equation W-16 of this subpart.
    (k) Transmission storage tanks. You must indicate whether your 
facility

[[Page 70418]]

contains any transmission storage tanks. If your facility contains at 
least one transmission storage tank, then you must report the 
information specified in paragraphs (k)(1) through (3) of this section 
for each transmission storage tank vent stack.
    (1) For each transmission storage tank vent stack, report the 
information specified in (k)(1)(i) through (iv) of this section.
    (i) The unique name or ID number for the transmission storage tank 
vent stack.
    (ii) Method used to determine if dump valve leakage occurred.
    (iii) Indicate whether scrubber dump valve leakage occurred for the 
transmission storage tank vent according to Sec.  98.233(k)(2).
    (iv) Indicate if there is a flare attached to the transmission 
storage tank vent stack.
    (2) If scrubber dump valve leakage occurred for a transmission 
storage tank vent stack, as reported in paragraph (k)(1)(iii) of this 
section, and the vent stack vented directly to the atmosphere during 
the calendar year, then you must report the information specified in 
paragraphs (k)(2)(i) through (v) of this section for each transmission 
storage vent stack where scrubber dump valve leakage occurred.
    (i) Method used to measure the leak rate.
    (ii) Measured leak rate (average leak rate from a continuous flow 
measurement device), in standard cubic feet per hour.
    (iii) Duration of time that the leak is counted as having occurred, 
in hours, as determined in Sec.  98.233(k)(3) (may use best available 
data if a continuous flow measurement device was used).
    (iv) Annual CO<INF>2</INF> emissions, in metric tons 
CO<INF>2</INF>, that resulted from venting gas directly to the 
atmosphere, calculated according to Sec.  98.233(k)(1) through (4).
    (v) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
that resulted from venting gas directly to the atmosphere, calculated 
according to Sec.  98.233(k)(1) through (4).
    (3) If scrubber dump valve leakage occurred for a transmission 
storage tank vent stack, as reported in paragraph (k)(1)(iii), and the 
vent stack vented to a flare during the calendar year, then you must 
report the information specified in paragraphs (k)(3)(i) through (vi) 
of this section.
    (i) Method used to measure the leak rate.
    (ii) Measured leakage rate (average leak rate from a continuous 
flow measurement device) in standard cubic feet per hour.
    (iii) Duration of time that flaring occurred in hours, as defined 
in Sec.  98.233(k)(3) (may use best available data if a continuous flow 
measurement device was used).
    (iv) Annual CO<INF>2</INF> emissions, in metric tons 
CO<INF>2</INF>, that resulted from flaring gas, calculated according to 
Sec.  98.233(k)(5).
    (v) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
that resulted from flaring gas, calculated according to Sec.  
98.233(k)(5).
    (vi) Annual N<INF>2</INF>O emissions, in metric tons 
N<INF>2</INF>O, that resulted from flaring gas, calculated according to 
Sec.  98.233(k)(5).
    (l) Well testing. You must indicate whether you performed gas well 
or oil well testing, and if the testing of gas wells or oil wells 
resulted in vented or flared emissions during the calendar year. If you 
performed well testing that resulted in vented or flared emissions 
during the calendar year, then you must report the information 
specified in paragraphs (l)(1) through (4) of this section, as 
applicable.
    (1) If you used Equation W-17A to calculate annual volumetric 
natural gas emissions at actual conditions from oil wells and the 
emissions are not vented to a flare, then you must report the 
information specified in paragraphs (l)(1)(i) through (vi) of this 
section.
    (i) Number of wells tested in the calendar year.
    (ii) Average number of well testing days per well for well(s) 
tested in the calendar year.
    (iii) Average gas to oil ratio for well(s) tested, in cubic feet of 
gas per barrel of oil.
    (iv) Average flow rate for well(s) tested, in barrels of oil per 
day. You may delay reporting of this data element if you indicate in 
the annual report that wildcat wells and/or delineation wells are the 
only wells that are tested. If you elect to delay reporting of this 
data element, you must report by the date specified in Sec.  98.236(cc) 
the measured average flow rate for well(s) tested and the API Well 
Number(s) for the well(s) included in the measurement.
    (v) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>, 
calculated according to Sec.  98.233(l).
    (vi) Annual CH<INF>4</INF> emissions, in metric tons 
CH<INF>4</INF>, calculated according to Sec.  98.233(l).
    (2) If you used Equation W-17A to calculate annual volumetric 
natural gas emissions at actual conditions from oil wells and the 
emissions are vented to a flare, then you must report the information 
specified in paragraphs (l)(2)(i) through (vii) of this section.
    (i) Number of wells tested in the calendar year.
    (ii) Average number of well testing days per well for well(s) 
tested in the calendar year.
    (iii) Average gas to oil ratio for well(s) tested, in cubic feet of 
gas per barrel of oil.
    (iv) Average flow rate for well(s) tested, in barrels of oil per 
day. You may delay reporting of this data element if you indicate in 
the annual report that wildcat wells and/or delineation wells are the 
only wells that are tested. If you elect to delay reporting of this 
data element, you must report by the date specified in Sec.  98.236(cc) 
the measured average flow rate for well(s) tested and the API Well 
Number(s) for the well(s) included in the measurement.
    (v) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>, 
calculated according to Sec.  98.233(l).
    (vi) Annual CH<INF>4</INF> emissions, in metric tons 
CH<INF>4</INF>, calculated according to Sec.  98.233(l).
    (vii) Annual N<INF>2</INF>O emissions, in metric tons 
N<INF>2</INF>O, calculated according to Sec.  98.233(l).
    (3) If you used Equation W-17B to calculate annual volumetric 
natural gas emissions at actual conditions from gas wells and the 
emissions were not vented to a flare, then you must report the 
information specified in paragraphs (l)(3)(i) through (v) of this 
section.
    (i) Number of wells tested in the calendar year.
    (ii) Average number of well testing days per well for well(s) 
tested in the calendar year.
    (iii) Average annual production rate for well(s) tested, in actual 
cubic feet per day. You may delay reporting of this data element if you 
indicate in the annual report that wildcat wells and/or delineation 
wells are the only wells that are tested. If you elect to delay 
reporting of this data element, you must report by the date specified 
in Sec.  98.236(cc) the measured average annual production rate for 
well(s) tested and the API Well Number(s) for the well(s) included in 
the measurement.
    (iv) Annual CO<INF>2</INF> emissions, in metric tons 
CO<INF>2</INF>, calculated according to Sec.  98.233(l).
    (v) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
calculated according to Sec.  98.233(l).
    (4) If you used Equation W-17B to calculate annual volumetric 
natural gas emissions at actual conditions from gas wells and the 
emissions were vented to a flare, then you must report the information 
specified in paragraphs (l)(4)(i) through (vi) of this section.
    (i) Number of wells tested in calendar year.
    (ii) Average number of well testing days per well for well(s) 
tested in the calendar year.
    (iii) Average annual production rate for well(s) tested, in actual 
cubic feet

[[Page 70419]]

per day. You may delay reporting of this data element if you indicate 
in the annual report that wildcat wells and/or delineation wells are 
the only wells that are tested. If you elect to delay reporting of this 
data element, you must report by the date specified in Sec.  98.236(cc) 
the measured average annual production rate for well(s) tested and the 
API Well Number(s) for the well(s) included in the measurement.
    (iv) Annual CO<INF>2</INF> emissions, in metric tons 
CO<INF>2</INF>, calculated according to Sec.  98.233(l).
    (v) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
calculated according to Sec.  98.233(l).
    (vi) Annual N<INF>2</INF>O emissions, in metric tons 
N<INF>2</INF>O, calculated according to Sec.  98.233(l).
    (m) Associated natural gas. You must indicate whether any 
associated gas was vented or flared during the calendar year. If 
associated gas was vented or flared during the calendar year, then you 
must report the information specified in paragraphs (m)(1) through (8) 
of this section for each sub-basin.
    (1) Sub-basin ID.
    (2) Indicate whether any associated gas was vented directly to the 
atmosphere without flaring.
    (3) Indicate whether any associated gas was flared.
    (4) Average gas to oil ratio, in standard cubic feet of gas per 
barrel of oil (average of the ``GOR'' values used in Equation W-18 of 
this subpart).
    (5) Volume of oil produced, in barrels, in the calendar year during 
the time periods in which associated gas was vented or flared (the sum 
of ``V<INF>p,q</INF>'' used in Equation W-18 of this subpart). You may 
delay reporting of this data element if you indicate in the annual 
report that wildcat wells and/or delineation wells are the only wells 
from which associated gas was vented or flared. If you elect to delay 
reporting of this data element, you must report by the date specified 
in Sec.  98.236(cc) the volume of oil produced for well(s) with 
associated gas venting and flaring and the API Well Number(s) for the 
well(s) included in the measurement.
    (6) Total volume of associated gas sent to sales, in standard cubic 
feet, in the calendar year during time periods in which associated gas 
was vented or flared (the sum of ``SG'' values used in Equation W-18 of 
Sec.  98.233(m)). You may delay reporting of this data element if you 
indicate in the annual report that wildcat wells and/or delineation 
wells from which associated gas was vented or flared. If you elect to 
delay reporting of this data element, you must report by the date 
specified in Sec.  98.236(cc) the measured total volume of associated 
gas sent to sales for well(s) with associated gas venting and flaring 
and the API Well Number(s) for the well(s) included in the measurement.
    (7) If you had associated gas emissions vented directly to the 
atmosphere without flaring, then you must report the information 
specified in paragraphs (m)(7)(i) through (iii) of this section for 
each sub-basin.
    (i) Total number of wells for which associated gas was vented 
directly to the atmosphere without flaring.
    (ii) Annual CO<INF>2</INF> emissions, in metric tons 
CO<INF>2</INF>, calculated according to Sec.  98.233(m)(3) and (4).
    (iii) Annual CH<INF>4</INF> emissions, in metric tons 
CH<INF>4</INF>, calculated according to Sec.  98.233(m)(3) and (4).
    (8) If you had associated gas emissions that were flared, then you 
must report the information specified in paragraphs (m)(8)(i) through 
(iv) of this section for each sub-basin.
    (i) Total number of wells for which associated gas was flared.
    (ii) Annual CO<INF>2</INF> emissions, in metric tons 
CO<INF>2</INF>, calculated according to Sec.  98.233(m)(5).
    (iii) Annual CH<INF>4</INF> emissions, in metric tons 
CH<INF>4</INF>, calculated according to Sec.  98.233(m)(5).
    (iv) Annual N<INF>2</INF>O emissions, in metric tons 
N<INF>2</INF>O, calculated according to Sec.  98.233(m)(5).
    (n) Flare stacks. You must indicate if your facility contains any 
flare stacks. You must report the information specified in paragraphs 
(n)(1) through (12) of this section for each flare stack at your 
facility, and for each industry segment applicable to your facility.
    (1) Unique name or ID for the flare stack. For the onshore 
petroleum and natural gas production industry segment, a different name 
or ID may be used for a single flare stack for each location where it 
operates at in a given calendar year.
    (2) Indicate whether the flare stack has a continuous flow 
measurement device.
    (3) Indicate whether the flare stack has a continuous gas 
composition analyzer on feed gas to the flare.
    (4) Volume of gas sent to the flare, in standard cubic feet 
(``V<INF>s</INF>'' in Equations W-19 and W-20 of this subpart).
    (5) Fraction of the feed gas sent to an un-lit flare 
(``Z<INF>u</INF>'' in Equation W-19 of this subpart).
    (6) Flare combustion efficiency, expressed as the fraction of gas 
combusted by a burning flare.
    (7) Mole fraction of CH<INF>4</INF> in the feed gas to the flare 
(``X<INF>CH4</INF>'' in Equation W-19 of this subpart).
    (8) Mole fraction of CO<INF>2</INF> in the feed gas to the flare 
(``X<INF>CO2</INF>'' in Equation W-20 of this subpart).
    (9) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF> 
(refer to Equation W-20 of this subpart).
    (10) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF> 
(refer to Equation W-19 of this subpart).
    (11) Annual N<INF>2</INF>O emissions, in metric tons N<INF>2</INF>O 
(refer to Equation W-40 of this subpart).
    (12) Indicate whether a CEMS was used to measure emissions from the 
flare. If a CEMS was used to measure emissions from the flare, then you 
are not required to report N<INF>2</INF>O and CH<INF>4</INF> emissions 
for the flare stack.
    (o) Centrifugal compressors. You must indicate whether your 
facility has centrifugal compressors. You must report the information 
specified in paragraphs (o)(1) and (2) of this section for all 
centrifugal compressors at your facility. For each compressor source or 
manifolded group of compressor sources that you conduct as found leak 
measurements as specified in Sec.  98.233(o)(2) or (4), you must report 
the information specified in paragraph (o)(3) of this section. For each 
compressor source or manifolded group of compressor sources that you 
conduct continuous monitoring as specified in Sec.  98.233(o)(3) or 
(5), you must report the information specified in paragraph (o)(4) of 
this section. Centrifugal compressors in onshore petroleum and natural 
gas production are not required to report information in paragraphs 
(o)(1) through (4) of this section and instead must report the 
information specified in paragraph (o)(5) of this section.
    (1) Compressor activity data. Report the information specified in 
paragraphs (o)(1)(i) through (xiv) of this section for each centrifugal 
compressor located at your facility.
    (i) Unique name or ID for the centrifugal compressor.
    (ii) Hours in operating-mode.
    (iii) Hours in not-operating-depressurized-mode.
    (iv) Indicate whether the compressor was measured in operating-
mode.
    (v) Indicate whether the compressor was measured in not-operating-
depressurized-mode.
    (vi) Indicate which, if any, compressor sources are part of a 
manifolded group of compressor sources.
    (vii) Indicate which, if any, compressor sources are routed to a 
flare.
    (viii) Indicate which, if any, compressor sources have vapor 
recovery.
    (ix) Indicate which, if any, compressor source emissions are 
captured for fuel use or are routed to a thermal oxidizer.

[[Page 70420]]

    (x) Indicate whether the compressor has blind flanges installed and 
associated dates.
    (xi) Indicate whether the compressor has wet or dry seals.
    (xii) If the compressor has wet seals, the number of wet seals.
    (xiii) Power output of the compressor driver (hp).
    (xiv) Indicate whether the compressor had a scheduled depressurized 
shutdown during the reporting year.
    (2) Compressor source. (i) For each compressor source at each 
compressor, report the information specified in paragraphs (o)(2)(i)(A) 
through (C) of this section.
    (A) Centrifugal compressor name or ID. Use the same ID as in 
paragraph (o)(1)(i) of this section.
    (B) Centrifugal compressor source (wet seal, isolation valve, or 
blowdown valve).
    (C) Unique name or ID for the leak or vent. If the leak or vent is 
connected to a manifolded group of compressor sources, use the same 
leak or vent ID for each compressor source in the manifolded group. If 
multiple compressor sources are released through a single vent for 
which continuous measurements are used, use the same leak or vent ID 
for each compressor source released via the measured vent. For a single 
compressor using as found measurements, you must provide a different 
leak or vent ID for each compressor source.
    (ii) For each leak or vent, report the information specified in 
paragraphs (o)(2)(ii)(A) through (E) of this section.
    (A) Indicate whether the leak or vent is for a single compressor 
source or manifolded group of compressor sources and whether the 
emissions from the leak or vent are released to the atmosphere, routed 
to a flare, combustion (fuel or thermal oxidizer), or vapor recovery.
    (B) Indicate whether an as found measurement(s) as identified in 
Sec.  98.233(o)(2) or (4) was conducted on the leak or vent.
    (C) Indicate whether continuous measurements as identified in Sec.  
98.233(o)(3) or (5) were conducted on the leak or vent.
    (D) Report emissions as specified in paragraphs (o)(2)(ii)(D)(1) 
and (2) of this section for the leak or vent. If the leak or vent is 
routed to a flare, combustion, or vapor recovery, you are not required 
to report emissions under this paragraph.
    (1) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2.</INF>
    (2) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4.</INF>
    (E) If the leak or vent is routed to flare, combustion, or vapor 
recovery, report the percentage of time that the respective device was 
operational when the compressor source emissions were routed to the 
device.
    (3) As found measurement sample data. If the measurement methods 
specified in Sec.  98.233(o)(2) or (4) are conducted, report the 
information specified in paragraph (o)(3)(i) of this section. If the 
calculation specified in Sec.  98.233(o)(6)(ii) is performed, report 
the information specified in paragraph (o)(3)(ii) of this section.
    (i) For each as found measurement performed on a leak or vent, 
report the information specified in paragraphs (o)(3)(i)(A) through (F) 
of this section.
    (A) Name or ID of leak or vent. Use same leak or vent ID as in 
paragraph (o)(2)(i)(C) of this section.
    (B) Measurement date.
    (C) Measurement method. If emissions were not detected when using a 
screening method, report the screening method. If emissions were 
detected using a screening method, report only the method subsequently 
used to measure the volumetric emissions.
    (D) Measured flow rate, in standard cubic feet per hour.
    (E) For each compressor attached to the leak or vent, report the 
compressor mode during which the measurement was taken.
    (F) If the measurement is for a manifolded group of compressor 
sources, indicate whether the measurement location is prior to or after 
comingling with non-compressor emission sources.
    (ii) For each compressor mode-source combination where a reporter 
emission factor as calculated in Equation W-23 was used to calculate 
emissions in Equation W-22, report the information specified in 
paragraphs (o)(3)(ii)(A) through (D) of this section.
    (A) The compressor mode-source combination.
    (B) The compressor mode-source combination reporter emission 
factor, in standard cubic feet per hour (EF<INF>s,m</INF> in Equation 
W-23).
    (C) The total number of compressors measured in the compressor 
mode-source combination in the current reporting year and the preceding 
two reporting years (Count<INF>m</INF> in Equation W-23).
    (D) Indicate whether the compressor mode-source combination 
reporter emission factor is facility-specific or based on all of the 
reporter's applicable facilities.
    (4) Continuous measurement data. If the measurement methods 
specified in Sec.  98.233(o)(3) or (5) are conducted, report the 
information specified in paragraphs (o)(4)(i) through (iv) of this 
section for each continuous measurement conducted on each leak or vent 
associated with each compressor source or manifolded group of 
compressor sources.
    (i) Name or ID of leak or vent. Use same leak or vent ID as in 
paragraph (o)(2)(i)(C) of this section.
    (ii) Measured volume of flow during the reporting year, in million 
standard cubic feet.
    (iii) Indicate whether the measured volume of flow during the 
reporting year includes compressor blowdown emissions as allowed for in 
Sec.  98.233(o)(3)(ii) and (o)(5)(iii).
    (iv) If the measurement is for a manifolded group of compressor 
sources, indicate whether the measurement location is prior to or after 
comingling with non-compressor emission sources.
    (5) Onshore petroleum and natural gas production. Centrifugal 
compressors with wet seal degassing vents in onshore petroleum and 
natural gas production must report the information specified in 
paragraphs (o)(5)(i) through (iii) of this section.
    (i) Number of centrifugal compressors that have wet seal oil 
degassing vents.
    (ii) Annual CO<INF>2</INF> emissions, in metric tons 
CO<INF>2</INF>, from centrifugal compressors with wet seal oil 
degassing vents.
    (iii) Annual CH<INF>4</INF> emissions, in metric tons 
CH<INF>4</INF>, from centrifugal compressors with wet seal oil 
degassing vents.
    (p) Reciprocating compressors. You must indicate whether your 
facility has reciprocating compressors. You must report the information 
specified in paragraphs (p)(1) and (2) of this section for all 
reciprocating compressors at your facility. For each compressor source 
or manifolded group of compressor sources that you conduct as found 
leak measurements as specified in Sec.  98.233(p)(2) or (4), you must 
report the information specified in paragraph (p)(3) of this section. 
For each compressor source or manifolded group of compressor sources 
that you conduct continuous monitoring as specified in Sec.  
98.233(p)(3) or (5), you must report the information specified in 
paragraph (p)(4) of this section. Reciprocating compressors in onshore 
petroleum and natural gas production are not required to report 
information in paragraphs (p)(1) through (4) of this section and 
instead must report the information specified in paragraph (p)(5) of 
this section.
    (1) Compressor activity data. Report the information specified in 
paragraphs (p)(1)(i) through (xiv) of this section for each 
reciprocating compressor located at your facility.

[[Page 70421]]

    (i) Unique name or ID for the reciprocating compressor.
    (ii) Hours in operating-mode.
    (iii) Hours in standby-pressurized-mode.
    (iv) Hours in not-operating-depressurized-mode.
    (v) Indicate whether the compressor was measured in operating-mode.
    (vi) Indicate whether the compressor was measured in standby-
pressurized-mode.
    (vii) Indicate whether the compressor was measured in not-
operating-depressurized-mode.
    (viii) Indicate which, if any, compressor sources are part of a 
manifolded group of compressor sources.
    (ix) Indicate which, if any, compressor sources are routed to a 
flare.
    (x) Indicate which, if any, compressor sources have vapor recovery.
    (xi) Indicate which, if any, compressor source emissions are 
captured for fuel use or are routed to a thermal oxidizer.
    (xii) Indicate whether the compressor has blind flanges installed 
and associated dates.
    (xiii) Power output of the compressor driver (hp).
    (xiv) Indicate whether the compressor had a scheduled depressurized 
shutdown during the reporting year.
    (2) Compressor source. (i) For each compressor source at each 
compressor, report the information specified in paragraphs (p)(2)(i)(A) 
through (C) of this section.
    (A) Reciprocating compressor name or ID. Use the same ID as in 
paragraph (p)(1)(i) of this section.
    (B) Reciprocating compressor source (isolation valve, blowdown 
valve, or rod packing).
    (C) Unique name or ID for the leak or vent. If the leak or vent is 
connected to a manifolded group of compressor sources, use the same 
leak or vent ID for each compressor source in the manifolded group. If 
multiple compressor sources are released through a single vent for 
which continuous measurements are used, use the same leak or vent ID 
for each compressor source released via the measured vent. For a single 
compressor using as found measurements, you must provide a different 
leak or vent ID for each compressor source.
    (ii) For each leak or vent, report the information specified in 
paragraphs (p)(2)(ii)(A) through (E) of this section.
    (A) Indicate whether the leak or vent is for a single compressor 
source or manifolded group of compressor sources and whether the 
emissions from the leak or vent are released to the atmosphere, routed 
to a flare, combustion (fuel or thermal oxidizer), or vapor recovery.
    (B) Indicate whether an as found measurement(s) as identified in 
Sec.  98.233(p)(2) or (4) was conducted on the leak or vent.
    (C) Indicate whether continuous measurements as identified in Sec.  
98.233(p)(3) or (5) were conducted on the leak or vent.
    (D) Report emissions as specified in paragraphs (p)(2)(ii)(D)(1) 
and (2) of this section for the leak or vent. If the leak or vent is 
routed to flare, combustion, or vapor recovery, you are not required to 
report emissions under this paragraph.
    (1) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2.</INF>
    (2) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4.</INF>
    (E) If the leak or vent is routed to flare, combustion, or vapor 
recovery, report the percentage of time that the respective device was 
operational when the compressor source emissions were routed to the 
device.
    (3) As found measurement sample data. If the measurement methods 
specified in Sec.  98.233(p)(2) or (4) are conducted, report the 
information specified in paragraph (p)(3)(i) of this section. If the 
calculation specified in Sec.  98.233(p)(6)(ii) is performed, report 
the information specified in paragraph (p)(3)(ii) of this section.
    (i) For each as found measurement performed on a leak or vent, 
report the information specified in paragraphs (p)(3)(i)(A) through (F) 
of this section.
    (A) Name or ID of leak or vent. Use same leak or vent ID as in 
paragraph (p)(2)(i)(C) of this section.
    (B) Measurement date.
    (C) Measurement method. If emissions were not detected when using a 
screening method, report the screening method. If emissions were 
detected using a screening method, report only the method subsequently 
used to measure the volumetric emissions.
    (D) Measured flow rate, in standard cubic feet per hour.
    (E) For each compressor attached to the leak or vent, report the 
compressor mode during which the measurement was taken.
    (F) If the measurement is for a manifolded group of compressor 
sources, indicate whether the measurement location is prior to or after 
comingling with non-compressor emission sources.
    (ii) For each compressor mode-source combination where a reporter 
emission factor as calculated in Equation W-28 was used to calculate 
emissions in Equation W-27, report the information specified in 
paragraphs (p)(3)(ii)(A) through (D) of this section
    (A) The compressor mode-source combination.
    (B) The compressor mode-source combination reporter emission 
factor, in standard cubic feet per hour (EF<INF>s,m</INF> in Equation 
W-28).
    (C) The total number of compressors measured in the compressor 
mode-source combination in the current reporting year and the preceding 
two reporting years (Count<INF>m</INF> in Equation W-28).
    (D) Indicate whether the compressor mode-source combination 
reporter emission factor is facility-specific or based on all of the 
reporter's applicable facilities.
    (4) Continuous measurement data. If the measurement methods 
specified in Sec.  98.233(p)(3) or (5) are conducted, report the 
information specified in paragraphs (p)(4)(i) through (iv) of this 
section for each continuous measurement conducted on each leak or vent 
associated with each compressor source or manifolded group of 
compressor sources.
    (i) Name or ID of leak or vent. Use same leak or vent ID as in 
paragraph (p)(2)(i)(C) of this section.
    (ii) Measured volume of flow during the reporting year, in million 
standard cubic feet.
    (iii) Indicate whether the measured volume of flow during the 
reporting year includes compressor blowdown emissions as allowed for in 
Sec.  98.233(p)(3)(ii) and (p)(5)(iii).
    (iv) If the measurement is for a manifolded group of compressor 
sources, indicate whether the measurement location is prior to or after 
comingling with non-compressor emission sources.
    (5) Onshore petroleum and natural gas production. Reciprocating 
compressors in onshore petroleum and natural gas production must report 
the information specified in paragraphs (p)(5)(i) through (iii) of this 
section.
    (i) Number of reciprocating compressors.
    (ii) Annual CO<INF>2</INF> emissions, in metric tons 
CO<INF>2</INF>, from reciprocating compressors.
    (iii) Annual CH<INF>4</INF> emissions, in metric tons 
CH<INF>4</INF>, from reciprocating compressors.
    (q) Equipment leak surveys. If your facility is subject to the 
requirements of Sec.  98.233(q), then you must report the information 
specified in paragraphs (q)(1) and (2) of this section. Natural gas 
distribution facilities with emission sources listed in Sec.  
98.232(i)(1) must also report the information specified in paragraph 
(q)(3) of this section.

[[Page 70422]]

    (1) You must report the information specified in paragraphs 
(q)(1)(i) and (ii) of this section.
    (i) Except as specified in paragraph (q)(1)(ii) of this section, 
the number of complete equipment leak surveys performed during the 
calendar year.
    (ii) Natural gas distribution facilities performing equipment leak 
surveys across a multiple year leak survey cycle must report the number 
of years in the leak survey cycle.
    (2) You must indicate whether your facility contains any of the 
component types listed in Sec.  98.232(d)(7), (e)(7), (f)(5), (g)(3), 
(h)(4), or (i)(1), for your facility's industry segment. For each 
component type that is located at your facility, you must report the 
information specified in paragraphs (q)(2)(i) through (v) of this 
section. If a component type is located at your facility and no leaks 
were identified from that component, then you must report the 
information in paragraphs (q)(2)(i) through (v) of this section but 
report a zero (``0'') for the information required according to 
paragraphs (q)(2)(iii), (iv), and (v) of this section.
    (i) Component type.
    (ii) Total number of the surveyed component type that were 
identified as leaking in the calendar year (``x<INF>p</INF>'' in 
Equation W-30 of this subpart for the component type).
    (iii) Average time the surveyed components are assumed to be 
leaking and operational, in hours (average of ``T<INF>p,z</INF>'' from 
Equation W-30 of this subpart for the component type).
    (iv) Annual CO<INF>2</INF> emissions, in metric tons 
CO<INF>2</INF>, for the component type as calculated using Equation W-
30 (for surveyed components only).
    (v) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
for the component type as calculated using Equation W-30 (for surveyed 
components only).
    (3) Natural gas distribution facilities with emission sources 
listed in Sec.  98.232(i)(1) must also report the information specified 
in paragraphs (q)(3)(i) through (viii) and, if applicable, (q)(3)(ix) 
of this section.
    (i) Number of above grade transmission-distribution transfer 
stations surveyed in the calendar year.
    (ii) Number of meter/regulator runs at above grade transmission-
distribution transfer stations surveyed in the calendar year 
(``Count<INF>MR,y</INF>'' from Equation W-31 of this subpart, for the 
current calendar year).
    (iii) Average time that meter/regulator runs surveyed in the 
calendar year were operational, in hours (average of 
``T<INF>w,y</INF>'' from Equation W-31 of this subpart, for the current 
calendar year).
    (iv) Number of above grade transmission-distribution transfer 
stations surveyed in the current leak survey cycle.
    (v) Number of meter/regulator runs at above grade transmission-
distribution transfer stations surveyed in current leak survey cycle 
(sum of ``Count<INF>MR,y</INF>'' from Equation W-31 of this subpart, 
for all calendar years in the current leak survey cycle).
    (vi) Average time that meter/regulator runs surveyed in the current 
leak survey cycle were operational, in hours (average of 
``T<INF>w,y</INF>'' from Equation W-31 of this subpart, for all years 
included in the leak survey cycle).
    (vii) Meter/regulator run CO<INF>2</INF> emission factor based on 
all surveyed transmission-distribution transfer stations in the current 
leak survey cycle, in standard cubic feet of CO<INF>2</INF> per 
operational hour of all meter/regulator runs (``EF<INF>s,MR,i</INF>'' 
for CO<INF>2</INF> calculated using Equation W-31 of this subpart).
    (viii) Meter/regulator run CH<INF>4</INF> emission factor based on 
all surveyed transmission-distribution transfer stations in the current 
leak survey cycle, in standard cubic feet of CH<INF>4</INF> per 
operational hour of all meter/regulator runs (``EF<INF>s,MR,i</INF>'' 
for CH<INF>4</INF> calculated using Equation W-31 of this subpart).
    (ix) If your natural gas distribution facility performs equipment 
leak surveys across a multiple year leak survey cycle, you must also 
report:
    (A) The total number of meter/regulator runs at above grade 
transmission-distribution transfer stations at your facility 
(``Count<INF>MR</INF>'' in Equation W-32B of this subpart).
    (B) Average estimated time that each meter/regulator run at above 
grade transmission-distribution transfer stations was operational in 
the calendar year, in hours per meter/regulator run 
(``T<INF>w,avg</INF>'' in Equation W-32B of this subpart).
    (C) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>, 
for all above grade transmission-distribution transfer stations at your 
facility.
    (D) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
for all above grade transmission-distribution transfer stations at your 
facility.
    (r) Equipment leaks by population count. If your facility is 
subject to the requirements of Sec.  98.233(r), then you must report 
the information specified in paragraphs (r)(1) through (3) of this 
section, as applicable.
    (1) You must indicate whether your facility contains any of the 
emission source types required to use Equation W-32A of this subpart. 
You must report the information specified in paragraphs (r)(1)(i) 
through (v) of this section separately for each emission source type 
required to use Equation W-32A of this subpart that is located at your 
facility. Onshore petroleum and natural gas production facilities must 
report the information specified in paragraphs (r)(1)(i) through (v) of 
this section separately by component type, service type, and geographic 
location (i.e., Eastern U.S. or Western U.S.).
    (i) Emission source type. Onshore petroleum and natural gas 
production facilities must report the component type, service type and 
geographic location.
    (ii) Total number of the emission source type at the facility 
(``Count<INF>e</INF>'' in Equation W-32A of this subpart).
    (iii) Average estimated time that the emission source type was 
operational in the calendar year, in hours (``T<INF>e</INF>'' in 
Equation W-32A of this subpart).
    (iv) Annual CO<INF>2</INF> emissions, in metric tons 
CO<INF>2</INF>, for the emission source type.
    (v) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
for the emission source type.
    (2) Natural gas distribution facilities must also report the 
information specified in paragraphs (r)(2)(i) through (v) of this 
section.
    (i) Number of above grade transmission-distribution transfer 
stations at the facility.
    (ii) Number of above grade metering-regulating stations that are 
not transmission-distribution transfer stations at the facility.
    (iii) Total number of meter/regulator runs at above grade metering-
regulating stations that are not above grade transmission-distribution 
transfer stations (``Count<INF>MR</INF>'' in Equation W-32B of this 
subpart).
    (iv) Average estimated time that each meter/regulator run at above 
grade metering-regulating stations that are not above grade 
transmission-distribution transfer stations was operational in the 
calendar year, in hours per meter/regulator run (``T<INF>w,avg</INF>'' 
in Equation W-32B of this subpart).
    (v) If your facility has above grade metering-regulating stations 
that are not above grade transmission-distribution transfer stations 
and your facility also has above grade transmission-distribution 
transfer stations, you must also report:
    (A) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>, 
from above grade metering-regulating stations that are not above grade 
transmission-distribution transfer stations.
    (B) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
from above grade metering regulating stations that are not above grade 
transmission-distribution transfer stations.

[[Page 70423]]

    (3) Onshore petroleum and natural gas production facilities must 
also report the information specified in paragraphs (r)(3)(i) and (ii) 
of this section.
    (i) Calculation method used.
    (ii) Onshore petroleum and natural gas production facilities must 
report the information specified in paragraphs (r)(3)(ii)(A) and (B) of 
this section, for each major equipment type, production type (i.e., 
natural gas or crude oil), and geographic location combination in 
Tables W-1B and W-1C of this subpart.
    (A) An indication of whether the facility contains the major 
equipment type.
    (B) If the facility does contain the equipment type, the count of 
the major equipment type.
    (s) Offshore petroleum and natural gas production. You must report 
the information specified in paragraphs (s)(1) through (3) of this 
section for each emission source type listed in the most recent BOEMRE 
study.
    (1) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>.
    (2) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>.
    (3) Annual N<INF>2</INF>O emissions, in metric tons N<INF>2</INF>O.
    (t) [Reserved]
    (u) [Reserved]
    (v) [Reserved]
    (w) EOR injection pumps. You must indicate whether CO<INF>2</INF> 
EOR injection was used at your facility during the calendar year and if 
any EOR injection pump blowdowns occurred during the year. If any EOR 
injection pump blowdowns occurred during the calendar year, then you 
must report the information specified in paragraphs (w)(1) through (8) 
of this section for each EOR injection pump system.
    (1) Sub-basin ID.
    (2) EOR injection pump system identifier.
    (3) Pump capacity, in barrels per day.
    (4) Total volume of EOR injection pump system equipment chambers, 
in cubic feet (``V<INF>v</INF>'' in Equation W-37 of this subpart).
    (5) Number of blowdowns for the EOR injection pump system in the 
calendar year.
    (6) Density of critical phase EOR injection gas, in kilograms per 
cubic foot (``R<INF>c</INF>'' in Equation W-37 of this subpart).
    (7) Mass fraction of CO<INF>2</INF> in critical phase EOR injection 
gas (``GHG<INF>CO2</INF>'' in Equation W-37 of this subpart).
    (8) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>, 
from EOR injection pump system blowdowns.
    (x) EOR hydrocarbon liquids. You must indicate whether hydrocarbon 
liquids were produced through EOR operations. If hydrocarbon liquids 
were produced through EOR operations, you must report the information 
specified in paragraphs (x)(1) through (4) of this section for each 
sub-basin category with EOR operations.
    (1) Sub-basin ID.
    (2) Total volume of hydrocarbon liquids produced through EOR 
operations in the calendar year, in barrels (``V<INF>hl</INF>'' in 
Equation W-38 of this subpart).
    (3) Average CO<INF>2</INF> retained in hydrocarbon liquids 
downstream of the storage tank, in metric tons per barrel under 
standard conditions (``S<INF>hl</INF>'' in Equation W-38 of this 
subpart).
    (4) Annual CO<INF>2</INF> emissions, in metric tons CO<INF>2</INF>, 
from CO<INF>2</INF> retained in hydrocarbon liquids produced through 
EOR operations downstream of the storage tank (``Mass<INF>CO2</INF>'' 
in Equation W-38 of this subpart).
    (y) [Reserved]
    (z) Combustion equipment at onshore petroleum and natural gas 
production facilities and natural gas distribution facilities. If your 
facility is required by Sec.  98.232(c)(22) or (i)(7) to report 
emissions from combustion equipment, then you must indicate whether 
your facility has any combustion units subject to reporting according 
to paragraphs (a)(1)(xvii) or (a)(8)(i) of this section. If your 
facility contains any combustion units subject to reporting according 
to paragraphs (a)(1)(xvii) or (a)(8)(i) of this section, then you must 
report the information specified in paragraphs (z)(1) and (2) of this 
section, as applicable.
    (1) Indicate whether the combustion units include: External fuel 
combustion units with a rated heat capacity less than or equal to 5 
million Btu per hour; or, internal fuel combustion units that are not 
compressor-drivers, with a rated heat capacity less than or equal to 1 
mmBtu/hr (or the equivalent of 130 horsepower). If the facility 
contains external fuel combustion units with a rated heat capacity less 
than or equal to 5 million Btu per hour or internal fuel combustion 
units that are not compressor-drivers, with a rated heat capacity less 
than or equal to 1 million Btu per hour (or the equivalent of 130 
horsepower), then you must report the information specified in 
paragraphs (z)(1)(i) and (ii) of this section for each unit type.
    (i) The type of combustion unit.
    (ii) The total number of combustion units.
    (2) Indicate whether the combustion units include: External fuel 
combustion units with a rated heat capacity greater than 5 million Btu 
per hour; internal fuel combustion units that are not compressor-
drivers, with a rated heat capacity greater than 1 million Btu per hour 
(or the equivalent of 130 horsepower); or, internal fuel combustion 
units of any heat capacity that are compressor-drivers. If your 
facility contains: External fuel combustion units with a rated heat 
capacity greater than 5 mmBtu/hr; internal fuel combustion units that 
are not compressor-drivers, with a rated heat capacity greater than 1 
million Btu per hour (or the equivalent of 130 horsepower); or internal 
fuel combustion units of any heat capacity that are compressor-drivers, 
then you must report the information specified in paragraphs (z)(2)(i) 
through (vi) of this section for each combustion unit type and fuel 
type combination.
    (i) The type of combustion unit.
    (ii) The type of fuel combusted.
    (iii) The quantity of fuel combusted in the calendar year, in 
thousand standard cubic feet, gallons, or tons.
    (iv) Annual CO<INF>2</INF> emissions, in metric tons 
CO<INF>2</INF>, calculated according to Sec.  98.233(z)(1) and (2).
    (v) Annual CH<INF>4</INF> emissions, in metric tons CH<INF>4</INF>, 
calculated according to Sec.  98.233(z)(1) and (2).
    (vi) Annual N<INF>2</INF>O emissions, in metric tons 
N<INF>2</INF>O, calculated according to Sec.  98.233(z)(1) and (2).
    (aa) Each facility must report the information specified in 
paragraphs (aa)(1) through (9) of this section, for each applicable 
industry segment, by using best available data. If a quantity required 
to be reported is zero, you must report zero as the value.
    (1) For onshore petroleum and natural gas production, report the 
data specified in paragraphs (aa)(1)(i) and (ii) of this section.
    (i) Report the information specified in paragraphs (aa)(1)(i)(A) 
through (C) of this section for the basin as a whole.
    (A) The quantity of gas produced in the calendar year from wells, 
in thousand standard cubic feet. This includes gas that is routed to a 
pipeline, vented or flared, or used in field operations. This does not 
include gas injected back into reservoirs or shrinkage resulting from 
lease condensate production.
    (B) The quantity of gas produced in the calendar year for sales, in 
thousand standard cubic feet.
    (C) The quantity of crude oil and condensate produced in the 
calendar year for sales, in barrels.
    (ii) Report the information specified in paragraphs (aa)(1)(ii)(A) 
through (M) of this section for each unique sub-basin category.
    (A) State.
    (B) County.
    (C) Formation type.

[[Page 70424]]

    (D) The number of producing wells at the end of the calendar year 
(exclude only those wells permanently taken out of production, i.e., 
plugged and abandoned) .
    (E) The number of producing wells acquired during the calendar 
year.
    (F) The number of producing wells divested during the calendar 
year.
    (G) The number of wells completed during the calendar year.
    (H) The number of wells permanently taken out of production (i.e., 
plugged and abandoned) during the calendar year.
    (I) Average mole fraction of CH<INF>4</INF> in produced gas.
    (J) Average mole fraction of CO<INF>2</INF> in produced gas.
    (K) If an oil sub-basin, report the average GOR of all wells, in 
thousand standard cubic feet per barrel.
    (L) If an oil sub-basin, report the average API gravity of all 
wells.
    (M) If an oil sub-basin, report average low pressure separator 
pressure, in pounds per square inch gauge.
    (2) For offshore production, report the quantities specified in 
paragraphs (aa)(2)(i) and (ii) of this section.
    (i) The total quantity of gas handled at the offshore platform in 
the calendar year, in thousand standard cubic feet, including 
production volumes and volumes transferred via pipeline from another 
location.
    (ii) The total quantity of oil and condensate handled at the 
offshore platform in the calendar year, in barrels, including 
production volumes and volumes transferred via pipeline from another 
location.
    (3) For natural gas processing, report the information specified in 
paragraphs (aa)(3)(i) through (vii) of this section.
    (i) The quantity of natural gas received at the gas processing 
plant in the calendar year, in thousand standard cubic feet.
    (ii) The quantity of processed (residue) gas leaving the gas 
processing plant in the calendar year, in thousand standard cubic feet.
    (iii) The cumulative quantity of all NGLs (bulk and fractionated) 
received at the gas processing plant in the calendar year, in barrels.
    (iv) The cumulative quantity of all NGLs (bulk and fractionated) 
leaving the gas processing plant in the calendar year, in barrels.
    (v) Average mole fraction of CH<INF>4</INF> in natural gas 
received.
    (vi) Average mole fraction of CO<INF>2</INF> in natural gas 
received.
    (vii) Indicate whether the facility fractionates NGLs.
    (4) For natural gas transmission compression, report the quantity 
specified in paragraphs (aa)(4)(i) through (v) of this section.
    (i) The quantity of gas transported through the compressor station 
in the calendar year, in thousand standard cubic feet.
    (ii) Number of compressors.
    (iii) Total compressor power rating of all compressors combined, in 
horsepower.
    (iv) Average upstream pipeline pressure, in pounds per square inch 
gauge.
    (v) Average downstream pipeline pressure, in pounds per square inch 
gauge.
    (5) For underground natural gas storage, report the quantities 
specified in paragraphs (aa)(5)(i) through (iii) of this section.
    (i) The quantity of gas injected into storage in the calendar year, 
in thousand standard cubic feet.
    (ii) The quantity of gas withdrawn from storage in the calendar 
year, in thousand standard cubic feet.
    (iii) Total storage capacity, in thousand standard cubic feet.
    (6) For LNG import equipment, report the quantity of LNG imported 
in the calendar year, in thousand standard cubic feet.
    (7) For LNG export equipment, report the quantity of LNG exported 
in the calendar year, in thousand standard cubic feet.
    (8) For LNG storage, report the quantities specified in paragraphs 
(aa)(8)(i) through (iii) of this section.
    (i) The quantity of LNG added into storage in the calendar year, in 
thousand standard cubic feet.
    (ii) The quantity of LNG withdrawn from storage in the calendar 
year, in thousand standard cubic feet.
    (iii) Total storage capacity, in thousand standard cubic feet.
    (9) For natural gas distribution, report the quantities specified 
in paragraphs (aa)(9)(i) through (vii) of this section.
    (i) The quantity of natural gas received at all custody transfer 
stations in the calendar year, in thousand standard cubic feet. This 
value may include meter corrections, but only for the calendar year 
covered by the annual report.
    (ii) The quantity of natural gas withdrawn from in-system storage 
in the calendar year, in thousand standard cubic feet.
    (iii) The quantity of natural gas added to in-system storage in the 
calendar year, in thousand standard cubic feet.
    (iv) The quantity of natural gas delivered to end users, in 
thousand standard cubic feet. This value does not include stolen gas, 
or gas that is otherwise unaccounted for.
    (v) The quantity of natural gas transferred to third parties such 
as other LDCs or pipelines, in thousand standard cubic feet. This value 
does not include stolen gas, or gas that is otherwise unaccounted for.
    (vi) The quantity of natural gas consumed by the LDC for 
operational purposes, in thousand standard cubic feet.
    (vii) The estimated quantity of gas stolen in the calendar year, in 
thousand standard cubic feet.
    (bb) For any missing data procedures used, report the information 
in Sec.  98.3(c)(8) except as provided in paragraphs (bb)(1) and (2) of 
this section.
    (1) For quarterly measurements, report the total number of quarters 
that a missing data procedure was used for each data element rather 
than the total number of hours.
    (2) For annual or biannual (once every two years) measurements, you 
do not need to report the number of hours that a missing data procedure 
was used for each data element.
    (cc) If you elect to delay reporting the information in paragraph 
(g)(5)(i), (g)(5)(ii), (h)(1)(iv), (h)(2)(iv), (j)(1)(iii), 
(j)(2)(i)(A), (l)(1)(iv), (l)(2)(iv), (l)(3)(iii), (l)(4)(iii), (m)(5), 
or (m)(6) of this section, you must report the information required in 
that paragraph no later than the date 2 years following the date 
specified in Sec.  98.3(b) introductory text.

0
9. Section 98.237 is amended by adding paragraph (f) to read as 
follows:


Sec.  98.237  Records that must be retained.

* * * * *
    (f) For each time a missing data procedure was used, keep a record 
listing the emission source type, a description of the circumstance 
that resulted in the need to use missing data procedures, the missing 
data provisions in Sec.  98.235 that apply, the calculation or analysis 
used to develop the substitute value, and the substitute value.

0
10. Section 98.238 is amended by:
0
a. Adding a definition for ``Associated gas venting or flaring'' in 
alphabetical order;
0
b. Removing the definition for ``Component'';
0
c. Adding definitions for ``Compressor mode'' and ``Compressor source'' 
in alphabetical order;
0
d. Removing the definitions for ``Equipment leak'' and ``Equipment leak 
detection'';
0
e. Adding definitions for ``Manifolded compressor source'' and 
``Manifolded group of compressor sources'' in alphabetical order;
0
f. Revising the definition for ``Meter/regulator run'';

[[Page 70425]]

0
g. Adding definitions for ``Reduced emissions completion'' and 
``Reduced emissions workover'' in alphabetical order; and
0
h. Revising the definition for ``Sub-basin category, for onshore 
natural gas production''.
    The revisions and additions read as follows:


Sec.  98.238  Definitions.

* * * * *
    Associated gas venting or flaring means the venting or flaring of 
natural gas which originates at wellheads that also produce hydrocarbon 
liquids and occurs either in a discrete gaseous phase at the wellhead 
or is released from the liquid hydrocarbon phase by separation. This 
does not include venting or flaring resulting from activities that are 
reported elsewhere, including tank venting, well completions, and well 
workovers.
* * * * *
    Compressor mode means the operational and pressurized status of a 
compressor. For a centrifugal compressor, ``mode'' refers to either 
operating-mode or not-operating-depressurized-mode. For a reciprocating 
compressor, ``mode'' refers to either: Operating-mode, standby-
pressurized-mode, or not-operating-depressurized-mode.
    Compressor source means the source of certain venting or leaking 
emissions from a centrifugal or reciprocating compressor. For 
centrifugal compressors, ``source'' refers to blowdown valve leakage 
through the blowdown vent, unit isolation valve leakage through an open 
blowdown vent without blind flanges, and wet seal oil degassing vents. 
For reciprocating compressors, ``source'' refers to blowdown valve 
leakage through the blowdown vent, unit isolation valve leakage through 
an open blowdown vent without blind flanges, and rod packing emissions.
* * * * *
    Manifolded compressor source means a compressor source (as defined 
in this section) that is manifolded to a common vent that routes gas 
from multiple compressors.
    Manifolded group of compressor sources means a collection of any 
combination of manifolded compressor sources (as defined in this 
section) that are manifolded to a common vent.
    Meter/regulator run means a series of components used in regulating 
pressure or metering natural gas flow, or both, in the natural gas 
distribution industry segment. At least one meter, at least one 
regulator, or any combination of both on a single run of piping is 
considered one meter/regulator run.
* * * * *
    Reduced emissions completion means a well completion following 
hydraulic fracturing where gas flowback emissions from the gas outlet 
of the separator that are otherwise vented are captured, cleaned, and 
routed to the flow line or collection system, re-injected into the well 
or another well, used as an on-site fuel source, or used for other 
useful purpose that a purchased fuel or raw material would serve, with 
de minimis direct venting to the atmosphere. Short periods of flaring 
during a reduced emissions completion may occur.
    Reduced emissions workover means a well workover with hydraulic 
fracturing (i.e., refracturing) where gas flowback emissions from the 
gas outlet of the separator that are otherwise vented are captured, 
cleaned, and routed to the flow line or collection system, re-injected 
into the well or another well, used as an on-site fuel source, or used 
for other useful purpose that a purchased fuel or raw material would 
serve, with de minimis direct venting to the atmosphere. Short periods 
of flaring during a reduced emissions workover may occur.
* * * * *
    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 five 
formation types: Oil, high permeability gas, shale gas, coal seam, or 
other tight gas reservoir rock. The distinction between high 
permeability gas and tight gas reservoirs shall be designated as 
follows: High permeability gas reservoirs with >0.1 millidarcy 
permeability, and tight gas reservoirs with <=0.1 millidarcy 
permeability. Permeability for a reservoir type shall be determined by 
engineering estimate. Wells that produce only from high permeability 
gas, shale gas, coal seam, or other tight gas reservoir rock are 
considered gas wells; gas wells producing from more than one of these 
formation types shall be classified into only one type based on the 
formation with the most contribution to production as determined by 
engineering knowledge. All wells that produce hydrocarbon liquids (with 
or without gas) and do not meet the definition of a gas well in this 
sub-basin category definition are considered to be in the oil 
formation. All emission sources that handle condensate from gas wells 
in high permeability gas, shale gas, or tight gas reservoir rock 
formations are considered to be in the formation that the gas well 
belongs to and not in the oil formation.
* * * * *
[FR Doc. 2014-27681 Filed 11-24-14; 8:45 am]
BILLING CODE 6560-50-P


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