6560.50

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 98

[EPA-HQ-OAR-2011-0512; FRL- XXXX-X]

RIN 2060-AR09

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

AGENCY:  Environmental Protection Agency (EPA).

ACTION:  Proposed Rule. 

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

DATES:  Comments.  Comments must be received on or before [INSERT THE
DATE, 30 DAYS AFTER PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL
REGISTER], unless a public hearing is held, in which case comments must
be received on or before [INSERT THE DATE 45 DAYS AFTER PUBLICATION OF
THIS PROPOSED RULE IN THE FEDERAL REGISTER].  

Public Hearing.  A public hearing will be held if requested.  To request
a hearing, please contact the person listed in the following FOR FURTHER
INFORMATION CONTACT section by [INSERT DATE 7 DAYS AFTER DATE OF
PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER].  If
requested, the hearing will be conducted on [INSERT DATE 15 DAYS AFTER
DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER], in
the Washington, DC area.  EPA will provide further information about the
hearing on its webpage if a hearing is requested.

ADDRESSES:  You may submit your comments, identified by Docket ID No. 
EPA-HQ-OAR-2011-0512 by any of the following methods:

Federal eRulemaking Portal: http://www.regulations.gov.  Follow the
online instructions for submitting comments.

Email: GHG_Reporting_Rule_Oil_And_Natural_Gas@epa.gov. Include Docket ID
No.  HYPERLINK
"https://fdms.erulemaking.net/fdms-web-agency/custom/jsp/agency/docketwi
zard/DocketWizardContainer.jsp" \t "_blank" EPA-HQ-OAR-2011- 0512 in the
subject line of the message.

Fax: (202) 566–9744.

Mail: Environmental Protection Agency, EPA Docket Center (EPA/DC), Mail
Code 28221T, Attention Docket ID No.  EPA-HQ-OAR–2011-0512, 1200
Pennsylvania Avenue, NW., Washington, DC 20460.

Hand/Courier Delivery: EPA Docket Center, Public Reading Room, EPA West
Building, Room 3334, Attention Docket ID No.  EPA-HQ-OAR–2011-0512,
1301 Constitution Avenue, NW., Washington, DC 20004.  Such deliveries
are only accepted during the docket’s normal hours of operation, and
special arrangements should be made for deliveries of boxed information.

Instructions:  Direct your comments to Docket ID No. 
EPA-HQ-OAR-2011-0512, Mandatory Reporting of Greenhouse Gases: Petroleum
and Natural Gas Systems.  EPA's policy is that all comments received
will be included in the public docket without change and may be made
available online at http://www.regulations.gov, including any personal
information provided, unless the comment includes information claimed to
be confidential business information (CBI) or other information whose
disclosure is restricted by statute.  Do not submit information that you
consider to be CBI or otherwise protected through
http://www.regulations.gov or email.  The http://www.regulations.gov web
site is an “anonymous access” system, which means EPA will not know
your identity or contact information unless you provide it in the body
of your comment.  If you send an email comment directly to EPA without
going through http://www.regulations.gov your email address will be
automatically captured and included as part of the comment that is
placed in the public docket and made available on the Internet.  If you
submit an electronic comment, EPA recommends that you include your name
and other contact information in the body of your comment and with any
disk or CD-ROM you submit.  If EPA cannot read your comment due to
technical difficulties and cannot contact you for clarification, EPA may
not be able to consider your comment.  Electronic files should avoid the
use of special characters, any form of encryption, and be free of any
defects or viruses.

Docket:  All documents in the docket are listed in the
http://www.regulations.gov index.  Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute.  Certain other material, such
as copyrighted material, will be publicly available for viewing at the
EPA Docket Center.  Publicly available docket materials are available
either electronically in http://www.regulations.gov or in hard copy at
the EPA Docket Center, EPA/DC, EPA West Building, Room 3334, 1301
Constitution Ave., NW., Washington, DC.  This Docket Facility is open
from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal
holidays.  The telephone number for the Public Reading Room is (202)
566-1744, and the telephone number for the Air Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Carole Cook, Climate Change Division,
Office of Atmospheric Programs (MC-6207J), Environmental Protection
Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone
number: (202) 343-9263; fax number: (202) 343-2342; email address:
GHGReportingRule@epa.gov.  For technical questions, please see the
Greenhouse Gas Reporting Program website
http://www.epa.gov/climatechange/emissions/ghgrulemaking.ht ml.  To
submit a question, select Rule Help Center, followed by Contact Us.  To
obtain information about the public hearing or to register to speak at
the public hearing, please go to
http://www.epa.gov/climatechange/emissions/ghgrulemaking.ht ml.
Alternatively, you may contact Carole Cook at 202–343–9263.

Worldwide Web (WWW).  In addition to being available in the docket, an
electronic copy of today's proposal will also be available through the
WWW.  Following the Administrator's signature, a copy of this action
will be posted on EPA's greenhouse gas reporting rule Web site at 
HYPERLINK
"http://www.epa.gov/climatechange/emissions/ghgrulemaking.html"
http://www.epa.gov/climatechange/emissions/ghgrulemaking.html .

Additional information on submitting comments.  To expedite review of
your comments by Agency staff, you are encouraged to send a separate
copy of your comments, in addition to the copy you submit to the
official docket, to Carole Cook, U.S. EPA, Office of Atmospheric
Programs, Climate Change Division, Mail Code 6207-J, Washington, DC
20460, telephone (202) 343-9263, email address:  HYPERLINK
"mailto:GHGReportingRule@epa.gov" GHGReportingRule@epa.gov . 

SUPPLEMENTARY INFORMATION:

Regulated Entities.  The Administrator determined that this action is
subject to the provisions of Clean Air Act (CAA) section 307(d).  If
finalized, these amended regulations could affect owners or operators of
petroleum and natural gas systems and certain electronic manufacturers. 
Regulated categories and entities may include those listed in Table 1 of
this preamble:

Table 1.  Examples of Affected Entities by Category

Source Category	NAICS	Examples of affected facilities

Petroleum and Natural Gas Systems	486210	Pipeline transportation of
natural gas.

	221210	Natural gas distribution facilities.

	211	Extractors of crude petroleum and natural gas.

	211112	Natural gas liquid extraction facilities.

Electronics Manufacturing	334111	Microcomputers manufacturing
facilities.

	334413	Semiconductor, photovoltaic (solid-state) device manufacturing
facilities.

	334419	Liquid Crystal Display (LCD) unit screens manufacturing
facilities.

	334419	Micro-electro-mechanical systems (MEMS) manufacturing
facilities.



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

Acronyms and Abbreviations.  The following acronyms and abbreviations
are used in this document.

AGA	American Gas Association

API	American Petroleum Institute

AXPC	American Exploration and Production Council

BAMM	Best Available Monitoring Methods

BOEMRE	Bureau of Ocean Energy Management, Regulation and Enforcement

CAA	Clean Air Act

CBI	confidential business information

CEC	Chesapeake Energy Corporation

CEMS	continuous emission monitoring systems

cfd	cubic feet per day

CFR	Code of Federal Regulations

CH4	methane

CO2	carbon dioxide

CO2e	CO2-equivalent

COR	certificate of representation

e-GGRT	electronic greenhouse gas reporting tool

EIA	Economic Impact Analysis

EOR	enhanced oil recovery

EPA	U.S. Environmental Protection Agency

FCML	Field Code Master List

FERC	Federal Energy Regulatory Commission

FR	Federal Register

GHG	greenhouse gas

GPA	Gas Processors Association

GOR	gas to oil ratio

GRI	Gas Research Institute

Hp	horsepower

GWP	global warming potential

HHV	high heat value

HTF	heat transfer fluid

IBR	incorporation by reference

ICR	information collection request

LDC	Local Distribution Company

ISO	International Organization for Standardization

kg	kilograms

LDCs	local natural gas distribution companies

LNG	liquefied natural gas

M&R	meters and regulators

mmBtu	million British thermal units

mmHg	millimeters of Mercury

MMscfd	million standard cubic feet per day

mTCO2e	million metric tons carbon dioxide equivalent 

MRR	mandatory GHG reporting rule

N2O	nitrous oxide

NAICS	North American Industry Classification System

NF3	nitrogen trifluoride

NGLs	natural gas liquids

NPS	nominal pipe size

NTTAA	National Technology Transfer and Advancement Act

OAQPS	Office of Air Quality, Planning and Standards

OMB	Office of Management and Budget

PHMSA	Pipeline and Hazardous Material Safety Administration

QA/QC	quality assurance/quality control

RFA	Regulatory Flexibility Act

SBA	Small Business Administration

SBREFA	Small Business Regulatory Enforcement and Fairness Act

SF6	sulfur hexafluoride

T-D	Transmission Distribution

TSD	technical support document

U.S.	United States

UMRA	Unfunded Mandates Reform Act of 1995

USC	United States Code

TABLE OF CONTENTS 

I.  Background

A.  How is this preamble organized?

B.  Background on the Proposed Action

C.  Legal Authority

D.  How would these amendments apply to 2012 reports?

II.  Technical Corrections and Other Amendments

A.  Subpart A – General Provisions

B.  Subpart I – Electronics Manufacturing

C.  Subpart W – Petroleum and Natural Gas Systems

III.  Statutory and Executive Order Reviews

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

B.  Paperwork Reduction Act

C.  Regulatory Flexibility Act (RFA)

D.  Unfunded Mandates Reform Act (UMRA)

E.  Executive Order 13132: Federalism

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

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

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

I.  National Technology Transfer and Advancement Act

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

I.  Background

A.  How is this preamble organized?

The first section of this preamble contains the basic background
information about the origin of these proposed rule amendments and
request for public comment.  This section also discusses EPA’s use of
legal authority under the CAA to collect data on GHGs. 

The second section of this preamble describes in detail the changes that
are being proposed to correct technical errors or to address
implementation issues identified by EPA and others.  This section also
presents EPA’s rationale for the proposed changes and identifies
issues on which EPA is particularly interested in receiving public
comments.

Finally, the last (third) section discusses the various statutory and
executive order requirements applicable to this proposed rulemaking. 

B.  Background on the Proposed Action

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

Following the publication of subpart I in the Federal Register, 3M
Company (3M) sought reconsideration of the final rule requirements for
reporting fluorinated heat transfer fluids (HTFs).  In this action EPA,
is proposing amendments to the provisions in subpart I related to
calculating and reporting fluorinated HTFs to reflect the Agency’s
intent to cover all fluorocarbons (except for ozone depleting substances
regulated under EPA’s Stratospheric Protection Regulations at 40 CFR
Part 82) that can enter the atmosphere under the conditions in which
HTFs are used in the electronics manufacturing industry. 

EPA published Subpart W: Petroleum and Natural Gas Systems of the
Greenhouse Gas Reporting Rule on November 30, 2010(75 FR 74458). 
Subpart W of the GHGRP, which applies to facilities in specific segments
of the petroleum and natural gas industry that emit GHGs greater than or
equal to 25,000 mtCO2e per year, covers approximately 85 percent of GHG
emissions – including vented, equipment leak, and combustion emissions
- from facilities in specific segments of the petroleum and natural gas
industry.         

Following the publication of subpart W in the Federal Register, several
industry groups requested reconsideration of several provisions in the
final rule.  Part of the proposed amendments in this action are in
response to those requests for reconsideration .  Today we are granting
reconsideration of, and requesting comment on, those issues raised in
the petitions listed in Table 2 where indicated in such Table that the
issue is addressed in this action.  While we do not necessarily agree
that each of those identified issues meet the criteria for
reconsideration, we nonetheless believe that they do raise important
implementation issues and are thus granting reconsideration of those
issues and proposing concomitant revisions to the rule. At this time we
are not granting reconsideration of other issues raised in those
petitions where indicated in the following table that they are not being
addressed in this action but will consider those issues at a later time.

Table 2: Petitions for Reconsideration

Petitioner and Date of Letter	Issue Raised for Reconsideration	Is this
issue addressed in this action?

American Gas Association by letter dated March 2, 2011	Non custody
transfer city gate station terminology.  AGA asserted that “[s]everal
provisions in the Subpart W rule and preamble seem to imply that a
‘non-custody-transfer city gate station’ will always have a
meter.”	Yes.

	Custody transfer city gate station terminology.  AGA asserted that the
term “custody transfer city gate station” in subpart W was unclear
and needed clarification.  	Yes.

	Use of GTI emission factors.  AGA requested reconsideration of the
emissions factors for Local Distribution Companies in the final rule.  
Partially.

	New emission factor formulas are confusing or contain math errors that
vastly inflate emission estimates.  AGA asserted that the “[t]he new
emissions factor equations W-30, W-31 and W-32 in the final rule are
confusing.  Since these formulas were not included in the proposed rule,
AGA did not have an opportunity to comment on them.”  	Yes. 

	New electronic reporting form is not yet available for comment or
testing.  AGA asserted that “[s]takeholders should be given the
opportunity to comment and to have access to the reporting software to
perform trial runs. 	No. This is being addressed in a separate package. 
 

	EPA should exclude small internal combustion sources, not just external
combustion.  AGA asserted that “EPA should revise the final rule to
provide a de minimis exemption for small internal and external
combustion sources at underground storage facilities.”  Also “AGA
request reconsideration of this new exclusion for small combustion
sources and revision to include both small internal and external
combustion sources…” 	Yes.

	AGA asserted that “[t]he rule contains conflicting provisions
regarding whether emissions from dehydrator units at underground storage
facilities should or should not be reported.”	No.  

	AGA asserted that “EPA did not provide rational explanation for using
outdated inaccurate emission factors rather than modern updated emission
factors.”	Yes.  

	AGA asserted that “[d]efinition of ‘facility’ is overbroad and
confusing.” The facility definition referred to here is found in 40
CFR 98.238.	No.

	AGA asserted that “It was arbitrary and capricious for EPA to create
a subpart W reporting regulation for a null set – LNG storage
facilities will not exceed the 25,000 ton per year threshold.”	No.

	AGA asserted that “It was arbitrary and capricious for EPA to create
a subpart W reporting regulation for LNG import and export facilities
– which have only minimal methane leaks.”	No.

Chesapeake Energy / American Exploration and Production Council by
Letter Dated January 31, 2011	Measurement of Emissions.  CEC/AXPC
asserted that “EPA proposed to require costly measurement and
reporting of emissions from hundreds of thousands of sources. 
Commenters asked EPA to adopt a reasonable threshold for measurement, so
that emissions could still be accounted for, but in a cost-effective
way.  Commenters recommended using the API Compendium for that
purpose.” 	No.

	De minimis emissions from portable equipment.  CEC/AXPC asserted that
“[t]he final rule likewise fails to adequately support requiring the
reporting of de minimis emissions from portable equipment as EPA
proposed…EPA asserts a truism that all emissions contribute to sector
emissions overall.”	Yes.

	Designated Representative.  CEC/AXPC requested reconsideration of the
designated representative provisions in the final rule.	Yes.

	Dump Valves.  CEC/AXPC asserts that “[t]he requirement to measure and
report emissions from dump valves associated with onshore production
storage tanks…is a new and unreasonable ongoing monitoring and record
keeping burden…”	No.

	Best Available Monitoring Methods.	No.  This is being addressed in a
separate action (76 FR 37300).  

	Emissions Manifolded to Common Vents.  CEC/AXPC asserted that the final
provisions for centrifugal compressor monitoring “[n]ot only expands
the rule to cover equipment that was not identified in the proposed
rule, but it is also inconsistent and creates ambiguity for covered
sources regarding what is required.” 	No.

	Compressor Monitoring.  CEC/AXPC asserts that “[t]he final rule
imposes a new obligation to monitor and report that would require major
piping modifications and that would unduly threaten worker safety.”
No.

	Excluding Boosting Stations.  CEC/AXPC asserted that “[t]he final
rule fails to distinguish between a boosting station, which is exempt,
and an ‘onshore natural gas transmission compression facility’ which
must report under the rule.”	Yes.

	Onshore Natural Gas Transmission Compression Industry Segment
Definition.  CEC/AXPC asserted that “[a]s presently drafted, the
unclear and inconsistent final provisions render the rule arbitrary and
capricious and contrary to law.” And “The term ‘onshore natural
gas transmission compression’ means a stationary combination of
compressors that move natural gas at elevated pressure from production
fields or natural gas processing facilities in transmission pipelines or
into storage.  40 C.F.R. §98.230(a)(4).  A transmission compressor
station can include equipment to separate liquids or dehydrate natural
gas Id.  However, according to the final rule this source category does
not include gathering lines and boosting stations.”	Yes.

	Onshore Natural Gas Processing Industry Segment Definition.  CEC/AXPC
asserted that “[a]s presently drafted, the unclear and inconsistent
final provisions render the rule arbitrary and capricious and contrary
to law.” CEC/AXPC further stated concerns with the definition for
onshore natural gas processing industry segment definition and where the
segment differs from onshore natural gas transmission industry segment,
and from gathering lines and boosting stations.  	Yes.

	Gathering Lines and Boosting Stations.  CEC/AXPC asserted that “EPA
noted that the ‘final rule does not require reporting of emissions
from [the] gathering and boosting segment of the industry.’ This…is
not helpful and gives industry no clarity regarding which compressor
stations are required to report.” 	Yes.

	Mapping Wells to Fields.  CEC/AXPC asserted that “EPA has not
clarified how reporting entities are supposed to map wells to a
particular ‘field.’” Also, CEC/AXPC asserted that “[w]ithout
sufficient clarity regarding what wells are in a particular field, it is
difficult for covered sources to know with certainty what gas
composition is considered representative for each well.”	Yes.

	Definition of Facility for Onshore Petroleum and Natural Gas
Production.  CEC/AXPC asserted that the “EPA has not provided a
reasoned explanation for why a term other than ‘facility’ cannot be
adopted for Subpart w (such as ‘Reporting Area’) in order to avoid
unintended confusion and inaccuracies in reporting.”	No.

	Pipeline Quality Natural Gas.  CEC/AXPC asserted that “[t]here is not
a clear and unambiguous definition in the final rule for ‘pipeline
quality’ natural gas.”	Yes.

	Producing Horizon/formation definition.  CEC/AXPC asserted that
“[t]here is not a clear and unambiguous definition provided in the
final rule for the term ‘producing horizon/formation.’”	Yes.

	Well testing venting and flaring clarification.  CEC/AXPC asserted that
“[t]he final rule is unclear regarding the requirement to report
emissions from well testing venting and flaring.”	Yes.

	Associated Gas Venting and Flaring.  CEC/AXPC asserted that “40 CFR
98.233(m) imposes a requirement to report emissions from associated gas
venting and flaring not in conjunction with well testing.  While this
regulation references 40 CFR 98.233(l), that definition is unclear. 
Therefore industry is left without clarity regarding what emissions are
included in ‘associated gas venting and flaring not in conjunction
with well testing.’” 	No.

	Pneumatic Devices.  CEC/AXPC asserted that “EPA has not given
sufficient consideration to the burden imposed by requiring that the
bleed rate of each device be determined in order to count and classify
the devices.”	Yes.

	Blowdown Vent Stacks.  CEC/AXPC asserted that “[t]he sources that are
required to report emissions from blowdown vent stacks are not clear.”
Yes.

American Petroleum Institute by Letter Dated January 31, 2011.  	Best
Available Monitoring Methods.	No.  This is being addressed in a separate
action (76 FR 37300).  

	Exclusion for ‘small’ internal combustion sources is needed.  API
asserted that “EPA should extend the exclusion for small external
combustion sources to small internal combustion sources.”	Yes. 

	Stuck dump valves to separators/tanks in onshore production operations.
 API asserted that “[t]he new requirement to report emissions from
stuck dump valves requires reporters to check all dump valves on a well
site… These requirements represent an administrative burden for
reports that was not contemplated in the proposed rule.”	No.  

	Reporting requirements for centrifugal and reciprocating compressor
venting at onshore natural gas processing facilities.  API requested EPA
to reconsider an asserted expansion of reporting requirements for
centrifugal and reciprocating compressor venting at onshore natural gas
processing facilities.  	No.

	Requirements for flare stack emission associated with onshore oil and
gas production.  API asserted that “[e]missions from flare stacks
associated with onshore oil and gas production were not included in the
Petroleum and Natural Gas production industry segment in the proposed
rule…the inclusion of emissions from flare stacks associated with
onshore oil and gas production is duplicative, burdensome, and a
potential source of reporting inaccuracies.”	Yes.  

	Reporting requirements for all venting and flaring activities in the
production source category.  API asserts that “EPA’s expansion of
the reporting obligations in 98.233(m) to include upset or maintenance
gas from producing wells imposes additional and extensive burdens on
regulated parties wich was not included in the proposal.”	No.  

	Use of gas composition based on available sample analysis for reporters
without continuous gas composition analyzer.  API asserts that “EPA
should resolve the ambiguity created by the current language.”	Yes.

	Portable combustion equipment that cannot move on roadways under its
own power and drive train that is stationed at a wellhead for less than
30 days in a reporting year.  API asserts that “[t]he final rule
requires reporters to account for this equipment, despite the fact that
it is on site for an extremely short period of time….it is unrealistic
to expect reporters to measure emissions from every piece of portable
combustion equipment that is only onsite for a matter of days.”	Yes.

	Separate calculations for Subsonic and supersonic flow when both happen
during a single completion.  API asserted that “[t]he proposed rule
did not include a requirement that well completions have separate
calculations for subsonic and supersonic flow when both occur during a
single completion.  The final rule adds this requirement, which is not
technically possible.” 	Yes.

	Flow meter requirements.  API asserts that “[t]he final rule adds a
requirement at 40 CFR 98.234(b) that all flow meters, composition
analyzers and pressure gauges be operated and calibrated according to
the procedures in Section 98.3(i) of the MRR…API is concerned about
the potential unintended consequence following the addition of
stationary source combustion equipment at a well pad at new 40 CFR
98.232(C)(22), which required compliance with 40 CFR 98.233(z)(2)(1).”
	Yes.

	Emission factors for continuous high-bleed, continuous low-bleed, and
intermittent bleed pneumatic devices.  API asserted that “[a]lthough
EPA has provided emission factors in Table W-1A that apply to continuous
high-bleed, continuous low-bleed, and intermittent bleed pneumatic
devices, EPA has not provided guidance on how to classify pneumatic
devices according to these three categories.”	Yes.

	Definitions to Industry Categories.  API asserted that the “[a]ltered
final rule creates ambiguity as to whether certain facilities are
included in the production category, excluded as gathering or booster
stations, or included under the gas processing category.” 	Yes.  

	Number of plunger lifts and average casing diameter in inches.  API
asserted that “[t]he final rule adds 40 CFR 98.236(c)(5) requirements
to report the number of plunger lifts and average casing diameter in
inches by field.  The difficulty with these additions is not with the
requirement for counting plunger lifts and noting casing diameter, but
that reporting must take place at the field level.” 	Yes.  

	Floating Production Storage and Offloading Equipment.  API asserted
that “[t]he proposed rule did not include floating production storage
and offloading equipment in the definition of offshore petroleum and
natural gas production.  API questions the need for this addition at 40
CFR 98.230(a)(1).” 	No.

	Basin level reporting for onshore petroleum and natural gas production.
 API asserted that “[t]his broad definition of onshore production
facility is impractical.  Subpart W imposes reporting requirements on
over 22,000 entities operating hundreds of thousands of wells and
millions of pieces of equipment scattered over hundreds of thousands of
square miles.” 	Yes.

	Field level reporting for onshore petroleum and natural gas production.
 API asserts that “[t]his level of reporting is problematic when
applied to new requirements of the final rule.  For the same reasons, it
remains problematic when applied to those requirements in the proposed
rule that remain in the final rule.”	Yes.  

	Designated Representative of Subpart W Facility.  API asserted that
“[t]he new basin-level facility definition for onshore petroleum and
natural gas production systems adopted in Subpart W adds unreasonable
complexity to several of the existing administrative requirements for
the designated representative set forth in 40 CFR 98.4” 	Yes.  

	Reporting of GHG emissions from leased, rented, or contracted
activities.  API asserts that “[t]hese requirements create significant
complications.  A single well pad may be owned by one entity, operated
by another entity, lease portable equipment from a third entity, and
have that portable equipment operated by yet another entity.  The rule
places the burden of reporting entirely on the owner of the well or the
holders of the operating permit and makes the designated representatives
legally responsible for the accuracy of the emissions data provided by
third parties.”	Partially.

	Threshold for “small” size units that are exempt from
consideration.  API asserts that “[t]he final rule’s threshold of
0.4 MMscf per day for dehydrator calculations using software and
individual reporting is too low.” 	No.

Gas Processors Association by Letter Dates February 11, 2011	Best
Available Monitoring Methods.  GPA asserted that “[s]ubpart W’s best
available monitoring method provisions do not provide reporting entities
with adequate time to ensure compliance with the final rule.”	No, this
is being addressed in a separate action (76 FR 37300).

	Compressor venting monitoring requirements.  GPA asserted that
“[c]urrent compressor venting monitoring requirements are overly
burdensome and present significant safety and operational process
concerns to reporting entities.”	No. 

	Use of the terms “gathering lines” and “booster stations” not
being defined in final rule.  GPA asserted that “[t]he terms
‘gathering lines’ and ‘booster stations’ are not defined in the
final rule, nor is sufficient detail provided regarding the definition
of ‘gas processing facility.’” GPA further asserted that
“[a]bsent such definitions and clarifications, there will be
substantial confusion as to which facilities are required to report
emissions data.”  	Yes.  

	Facility definition for onshore petroleum and natural gas production. 
GPA asserted “[t]he definition of a facility in Subpart W differs from
the definition of a facility provided in all other applicable
regulations under the Clean Air Act.  This inconsistency will create
unnecessary confusion among related programs and is not necessary or
justified.”	No.  

Southwest Gas Corporation by Letter Dated January 31, 2011	Terms in
Subpart W.  Southwest Gas Corporation asserted that “[t]he USEPA’s
final rule fails to provide clear definitions that can be used uniformly
throughout the natural gas distribution industry.” 	Yes.

	Errors in Calculations.  Southwest Gas Corporation asserted that the
USEPA published errors in equations in 40 CFR 98.233, namely equation
W-32.  	Yes.

Interstate Natural Gas Association of America 	Best Available Monitoring
Methods.  	No, this is being addressed in a separate action (76 FR
37300).

	Technical Provisions in Subpart W. INGAA asserted that “[n]umerous
technical elements of Subpart W remain unclear, confusing, overly
complicated or conflicting.” 	Partially.

	INGAA petitioned EPA to reconsider the default gas compositions and
requested the use of separate default gas compositions for methane and
CO2 for vented and fugitive emissions for the natural gas transmission
compression and storage segments.  	Yes.

	INGAA petitioned EPA to reconsider minor clarifications to 40 CFR
98.233(t), (u), and (v) for clarity	Yes.

	INGAA requested EPA to reconsider the provisions in the final rule for
determining the type of pneumatic device at a facility.  INGAA requested
EPA to consider the option of using engineering estimates to determine
the type of pneumatic devices.	Yes.

	INGAA requested EPA to reconsider the provisions in the rule related to
blowdown vent stacks and requested a  reconsideration of those
provisions.  	Yes.

	INGAA requested EPA to reconsider the provisions in the rule for
emissions from blowdown vent stacks and to include an additional
equation to allow facilities who currently track emissions by equipment
type to submit emission to EPA in that manner.	Yes.

	INGAA requested that EPA to reconsider provisions related to flaring.
Yes.

	INGAA requested that EPA reconsider provisions for monitoring emissions
from centrifugal and reciprocating compressors and to consider including
clarifications to rule text.  	No.

	INGAA requested EPA to reconsider provisions related to monitoring and
QA/QC requirements including  provisions for the alternative work
practice.  	Yes.

	INGAA requested EPA to reconsider missing data provisions and broaden
access.	No.

	INGAA requested EPA to reconsider provisions as stated in 40 CFR 98.236
and requested several clarifications to final text.  	Partially.  



The proposed amendments in this action include technical corrections and
clarifications to ensure that the 2010 final rule is implemented as
intended.  Amendments to subparts I and W are also being proposed in
other actions.  Please see 76 FR 47392 (Herein referred to as the
“technical corrections rule”) and76 FR 37300.  This proposal
complements these proposed rules and is not intended to duplicate or
replace those proposed amendments.  In limited cases, an amendment to
subpart W was proposed in the technical corrections rule and we are
proposing to amend it further in this action.  Additional proposed
amendments were determined to be necessary to address questions and
issues raised by stakeholders since development of the proposal of the
technical corrections rule.  Where amendments have been made to the same
paragraph in this action and in the technical corrections rule, the
proposal below provides the complete proposed amendatory language for
how EPA proposes to amend the provision.  We are seeking public comment
only on the issues specifically identified in this proposal for the
identified subparts.  We will not respond to any comments addressing
other aspects of Part 98 or any other related rulemakings. 

EPA promulgated confidentiality determinations for certain data elements
required to be reported under Part 98 and finalized amendments to the
Special Rules Governing Certain Information Obtained Under the Clean Air
Act, which authorizes EPA to release or withhold as confidential
reported data according to the confidentiality determinations for such
data without taking further procedural steps (76 FR 30782, May 26, 2011
hereinafter referred to as the “May 26, 2011 Final CBI Rule”).  That
notice addressed reporting of data elements in 34 subparts that were
determined not to be inputs to emission equations and therefore were not
proposed to have their reporting deadline deferred.  That rule did not
make confidentiality determinations for eight subparts, including
subpart W,  for which reporting requirements were finalized after
publication of the July 7, 2010 CBI proposal and July 20, 2010
supplemental CBI proposal.   

EPA is planning to address the confidentiality determinations for the
data elements in subpart W in a separate action.  EPA plans to issue and
finalize the confidentiality determinations for subpart W prior to the
2012 reporting deadline.  

C.  Legal Authority

EPA is proposing these rule amendments under its existing CAA authority,
specifically authorities provided in section 114 of the CAA. 

As stated in the preamble to the 2009 Final Greenhouse Gas Reporting
Rule (Part 98) (74 FR 56260, October 30, 2009), CAA section 114 provides
EPA broad authority to require the information proposed to be gathered
by this rule because such data would inform and are relevant to EPA’s
carrying out a wide variety of CAA provisions.  As discussed in the
preamble to the initial proposed rule (74 FR 16448, April 10, 2009),
section 114(a)(1) of the CAA authorizes the Administrator to require
emissions sources, persons subject to the CAA, manufacturers of control
or process equipment, or persons whom the Administrator believes may
have necessary information to monitor and report emissions and provide
such other information the Administrator requests for the purposes of
carrying out any provision of the CAA.  For further information about
EPA’s legal authority, see the preambles to the proposed and 2009
final Part 98. 

D.  How Would These Amendments Apply to 2012 Reports?

EPA is planning to address the comments on these proposed amendments and
publish the final amendments before the end of 2011.  Therefore, for
subpart W, reporters would be expected to calculate emissions and other
relevant data for the reports that are submitted in 2012 using part 98,
as amended by this rule, as finalized.  We have determined that it is
feasible for the sources to implement these changes for the 2011
reporting year since the proposed revisions primarily provide additional
clarifications or flexibility regarding the existing regulatory
requirements, generally do not affect the type of information that must
be collected, and do not substantially affect how emissions are
calculated.  

For amendments being proposed today to subpart I, EPA is requesting
comment on whether to require electronics manufacturing facilities to
estimate and report 2011 emissions in 2012 for HTFs that would be newly
included in the scope of subpart I if today’s proposed rule amendments
were finalized.   

For facilities subject to the provisions in 40 CFR part 98 – subpart
W, many proposed revisions simply provide additional information and
clarity on existing requirements.  For instance, we are proposing to
amend 40 CFR 98.1(c)(1) to clarify that for onshore petroleum and
natural gas facilities, the references in 40 CFR 98.4 that apply to
owner(s) and operator(s) refer to the onshore petroleum and natural gas
production owner or operator, as defined in 40 CFR 98.238.  Therefore,
we are proposing to explicitly make this clarification in 40 CFR 98.1
(Purpose and Scope).  The proposed amendment does not change the burden
of the 2010 final rule, and in fact, EPA believes that it alleviates
concerns expressed by industry that the designated representative
provisions are overly burdensome. 

Some of the proposed amendments for subpart W provide greater
flexibility or simplified calculation methods for certain facilities. 
For example, we are proposing to amend 40 CFR 98.233(i) to provide an
additional option to calculate GHG emissions from blowdown vent stacks. 
Specifically, we are proposing to allow reporters the option of tracking
blowdowns by each occurrence for the same blowdown volume, consistent
with current practice at some facilities, whereas in the final rule,
reporters were required to track  total blowdown vent emissions from all
occurrences for the same blowdown volume in a year.       

Further, some proposed amendments for subpart W are to the data
reporting requirements to provide additional clarity on which GHG
emissions have to be reported and at which level of aggregation.  For
example, in 40 CFR 98.236 EPA is proposing to clarify where “vented”
emissions should be reported separately from “flared” emissions and
that reporting of CH4, CO2, and N2O emissions should be reported
individually for each source type in CO2e.  We have concluded that
amendments such as these could be implemented for the reports submitted
to EPA in 2012 because the proposed changes are, with one exception,
consistent with the calculation methodologies already in part 98 and the
owners or operators are not required to actually report until March
2012, several months after we expect this proposal to be finalized.  

The one exception where both the underlying calculation requirements and
reporting requirements in subpart W are proposed to be changed is
related to the requirements for field level reporting for four emissions
sources in the onshore petroleum and natural gas production segment.  As
described further in Section II.C of this preamble, we are proposing to
amend the calculation and reporting requirements for well completions
and well workovers, well venting for liquids unloading, and storage
tanks to require calculations and reporting to be undertaken at the
county level and by geologic formation (by formation type).  

EPA believes that the proposed amendments for subpart W can still be
implemented for the 2011 reporting year for a couple of reasons.  First,
these amendments are being proposed based on industry concern about
associating wells with a particular “field” given possible ambiguity
surrounding EIA field designations.  While EPA maintains its belief that
reporting by the field is a viable and workable option, however, EPA
does acknowledge that counties are readily identifiable, and provide
clear geographic boundaries.  AS a result, implementation of this
alternative method should be straightforward for facilities.  Second, if
facilities are concerned about their ability to implement these
provisions for the 2011 reporting year, they may use best available
monitoring methods (BAMM) pursuant to 40 CFR 98.234(f).  In the event
that facilities have already taken a measurement at the field level,
they could still use those same measurements for the 2011 reporting
year, but apply them to the sub-basin categories based on BAMM.   

Other amendments to subpart W are proposed to address issues identified
as a result of working with the affected facilities during rule
implementation.  These proposed revisions provide additional flexibility
to the sources, or reduce the reporting burden.  For example, the 2010
final rule required leak detection for emissions from dump valves in
transportation storage tanks, and if a leak is detected, measurement of
the quantity of emissions would be required.  However, industry raised
questions as to whether a facility could forgo leak detection and
directly measure the emissions from leaking dump valves under the
natural gas transmission industry segment.  This action provides this
additional flexibility, because it reduces burden without compromising
the quality of the data reported to EPA.  

We are also proposing corrections to terms and definitions in certain
equations in subpart W.  For example, we are proposing to amend the
calculation for estimating CO2 emissions from acid gas removal vents in
Equation W-4.  Although the existing equation is appropriate when the
amount of CO2 in gas is relatively low, such as 1 percent, the error
rate in the estimate increases significantly as the amount of CO2 in gas
increases.  Therefore, EPA is proposing a new equation, which uses the
exact same input parameters and thus will not result in any additional
burden to reporters, but will improve the quality of the information
submitted to EPA.  These clarifications do not result in additional
requirements; therefore, we have concluded that reporters can follow
part 98, as amended, in submitting their first reports to EPA in 2012.

Finally, we are proposing other technical corrections in subpart W that
have no impact on a facility’s data collection efforts in 2011.  For
example, we are proposing to correct cross references in equations and
change incorrect use of the term “facility” in the definition of the
source category.

In summary, these proposed amendments to subpart W generally would not
require any additional monitoring or information collection above what
is already included in Part 98.  Therefore, we expect that sources can
use the same information that they have been collecting under the
current version of Part 98 to calculate and report GHG emissions for
2011 and submit reports in 2012 under Part 98, as amended by this
action. 

We seek comment on whether it is appropriate to implement these
amendments and incorporate the requirements in the data reported to EPA
by March 31, 2012.  Further, we seek comment on whether there are
specific provisions in subpart W for which this timeline may not be
feasible or appropriate due to the nature of the proposed changes or the
way in which data have been collected thus far in 2011.  We request that
commenters provide specific examples of how the proposed implementation
schedule would or would not work.  

II. Technical Corrections and Other Amendments

Following promulgation of the 2010 final subpart I and subpart W, EPA
has identified errors in the regulatory language that we are now
proposing to correct.  These issues were identified as a result of
working with affected industries to implement rules.  We have also
identified certain rule provisions that should be amended to provide
greater clarity.  For additional background information on the questions
raised, please refer to the Technical Support Document for this proposed
rulemaking available in the docket to this rulemaking
(EPA–HQ–OAR–2011-0512).  

The amendments we are now proposing include the following types of
changes: 

Changes to correct cross references within the subparts.

Additional information to allow reporters to better or more fully
understand compliance obligations in a specific provision.

Corrections to terms and definitions in certain equations.

Corrections to data reporting requirements so that they more closely
conform to the information used to perform emission calculations.

Other amendments related to certain issues identified as a result of
working with the affected sources during rule implementation and
outreach.

We are seeking public comment only on the issues specifically identified
in this notice for the identified subparts.  We will not respond to any
comments addressing other aspects of Part 98 or any other related
rulemakings.

A.  Subpart A – General Provisions 

Designated Representative.  Two industry associations raised concerns
about the provisions related to determination of the designated
representative in the context of how the subpart A definition would
affect subpart W reporters.  Through a letter dated January 31, 2011,
the American Petroleum Institute (API)  encouraged EPA to reconsider the
implications on owners and operators in the onshore petroleum and
natural gas production segment in the context of the provisions in 40
CFR 98.4.  Specifically, API was concerned that given the definition of
“facility” for onshore petroleum and natural gas production, coupled
with the relatively complex ownership structures in the industry (as
compared to other subparts covered under part 98), EPA should modify
several requirements in 40 CFR 98.4(authorization and responsibilities
of the designated representative).  API encouraged EPA to eliminate the
requirement of notifying co-owners of the designated representative
selection (40 CFR 98.4(i)(4)(iv)), eliminate the requirement for listing
of co-owners as part of the certificate of representation (40 CFR
98.4(i)(3), and eliminate the requirement for new certificates of
representation following ownership changes (40 CFR 98.4(h)).   

Similar concerns were expressed in a letter from Chesapeake Energy
Corporation (CEC) and the American Exploration & Production Council
(AXPC) dated January 31, 2011.  CEC/AXPC was also concerned that the
current operational reality in the onshore petroleum and natural gas
industry would make it difficult for a designated representative to make
the certifications required in 40 CFR 98.4(i)(4).  Specifically,
CEC/AXPC was concerned about attesting to the fact that the designated
representative was selected by an agreement binding on the owners and
operators of the facility, that all owners and operators are fully bound
by representations of the designated representative, that the owners and
operators of the facility would be bound by any order issued to the
designated representative by the administrator or a court, and that the
designated representative has given written notice of their selection
and of the agreement by which the designated was selected by the owner
and operator of the facility. 

EPA maintains, as described in the October 2009 final rule (74 FR
56357), that the high level of public interest in the data collected
under this rule, as well as its importance to future policy, warrants
establishment, by rule pursuant to CAA sections 114, 208, and 301(a)(1),
of a high standard for data quality and consistency and a high level of
accountability for reported data, which will help ensure that the data
quality and consistency standard is met.  The designated representative
is the primary point of contact between the owner or operator and the
EPA.  Therefore, it is important that EPA knows who the designated
representative is, and that the designated representative has made the
necessary certification statements.  

EPA recognizes that the onshore petroleum and natural gas industry has a
different organizational structure and operational realities than other
industries subject to Part 98.  As such, in the 2010 final rule for
subpart W (75 FR 74512), EPA specifically defined who is an onshore
petroleum and natural gas production owner or operator.  Under 40 CFR
98.238, onshore petroleum and natural gas production owner or operator
means “the person or entity who holds the permit to operate petroleum
and natural gas wells on the drilling permit or an operating permit
where no drilling permit is issued, which operates an onshore petroleum
and/or natural gas production facility (as described in 40 CFR
98.230(a)(2).  Where petroleum and natural gas wells operate without a
drilling or operating permit, the person or entity that pays the state
or federal business income taxes is considered the owner or operator.”
 It was EPA’s intent that this definition of owner and operator apply
not only in subpart W, but also in subpart A for the obligations of
Subpart W “owners and operators” (e.g., those related to identifying
the designated representative and requirement for who must be included
on the Certificate of Representation (COR)).  

EPA acknowledges that the final subpart W rule is not clear, and it
could be interpreted that all “owners” and all “operators”, as
defined in 40 CFR 98.6, are required to identify the designated
representative for the facility and be held accountable for all
requirements under 40 CFR 98.4.  EPA never intended that 4,000 owners
and operators, e.g., would have to be listed on the COR, an example
provided by API in their Petition for Reconsideration.   Rather, EPA
intended  that for onshore petroleum and natural gas facilities, the
references in 40 CFR 98.4 that apply to owner(s) and operator(s) refer
to the onshore petroleum and natural gas production operator, as defined
in 40 CFR 98.238.  Therefore, we are proposing to explicitly make this
clarification in 40 CFR 98.1 (Purpose and Scope).   

Definitions:  We are proposing amendments to the definition of
continuous bleed pneumatic device in 40 CFR 98.6 to clarify that
continuous bleed devices supply gas to process control devices; these
are not necessarily measurement devices, as suggested by the 2010 final
rule.

Similarly, we are proposing to amend the definition of an intermittent
bleed pneumatic device to clarify that these devices automatically
maintain the process conditions and that the devices discharge all or a
portion of the full volume of the actuator intermittently.  

Incorporation by Reference (IBR).  Finally we are also proposing to
amend 40 CFR 98.7 (What standardized methods are incorporated by
reference into this part?) to remove paragraph 40 CFR 98.7(q).  As
elaborated further below, we are proposing to change the calculation and
reporting requirements for specific equipment in the onshore petroleum
and natural gas production segment from a “field” level, to a
sub-basin category.  Consistent with this proposed amendment, there is
no longer a need to incorporate the Energy Information Administration
(EIA) Oil and Gas Field Code Master List, 2008.    

B.  Subpart I – Electronics Manufacturing

In this action, EPA is proposing to amend the provisions contained
within subpart I to calculate and report emissions from fluorinated GHGs
used as HTFs.  First, EPA is proposing to amend the definition of HTFs
in 40 CFR 98.98, to include all fluorocarbons used as HTFs in the
electronics manufacturing industry.  The definition of HTFs incorporates
the term “fluorinated GHGs” as defined in the general provisions of
the greenhouse gas reporting rule (subpart A) at 40 CFR 98.6.  The
definition of “fluorinated greenhouse gas” in subpart A excludes
“substances with vapor pressures of less than 1 mm of Hg absolute at
25 degrees C.”  EPA is proposing to specify that the vapor pressure
cutoff clause in the subpart A definition of fluorinated GHGs does not
apply to fluorinated HTFs in subpart I.  As a result, emissions of
fluorinated HTFs with vapor pressures of less than 1 mm of Hg absolute
at 25 degrees C would no longer be excluded from reporting under subpart
I.  Second, also in the definition of HTFs, EPA is proposing to add the
phrase “but not limited to” before listing examples of fluorinated
HTFs to ensure that potential future alternatives are covered.  Third,
EPA is proposing to remove the last sentence in the definition
(“Electronics manufacturers may also use these same fluorinated
chemicals to clean substrate surfaces or other parts”) and move the
concept of using HTFs to clean substrate surfaces or other parts to the
first sentence.  Fourth, EPA is proposing minor revisions throughout the
subpart I regulatory text to clarify the use of the terms fluorinated
GHGs and fluorinated HTFs (e.g., referring to fluorinated HTFs rather
than fluorinated GHGs used as HTFs).  And last, in 40 CFR 98.92(a)(5),
under GHGs to report, EPA is proposing to revise  the clause
“fluorinated GHG emitted from heat transfer use” to read
“emissions of fluorinated heat transfer fluids.”  

EPA published Subpart I: Electronics Manufacturing of Part 98 on
December 1, 2010 (75 FR 74774).  This subpart requires monitoring and
reporting of GHG emissions from electronics manufacturing.  Included in
the December 1, 2010 final rule are provisions that require electronics
manufacturing facilities to calculate and report emissions from the use
of fluorinated HTFs.  Pursuant to 40 CFR 98.93(h), electronics
manufacturing facilities must calculate HTF emissions using a mass
balance approach based on: the beginning and end of year inventories;
acquisitions and disbursements of HTFs; and the nameplate capacities of
newly installed and removed equipment containing HTFs.  For purposes of
subpart I, HTFs are defined as the following: “fluorinated GHGs used
for temperature control, device testing, and soldering in certain types
of electronic manufacturing production processes.  HTFs used in the
electronics sector include perfluoropolyethers, perfluoroalkanes,
perfluoroethers, tertiary perfluoroamines, and perfluorocyclic ethers. 
Electronics manufacturers may also use these same fluorinated chemicals
to clean substrate surfaces and other parts” (40 CFR 98.98).  

The definition of HTFs in subpart I includes the term “fluorinated
greenhouse gases” (fluorinated GHGs), which is defined in Subpart A:
General Provisions (40 CFR 98.6).  EPA initially proposed a definition
of fluorinated GHGs in the April 2009 proposed rule for Part 98 (74 FR
16448) as follows: “Fluorinated GHG means sulfur hexafluoride (SF6),
nitrogen trifluoride (NF3), and any fluorocarbon except for controlled
substances as defined at 40 CFR part 82, subpart A.  In addition to
(SF6) and NF3, “fluorinated GHG” includes but is not limited to any
hydrofluorocarbon, any perfluorocarbon, any fully fluorinated linear,
branched or cyclic alkane, ether, tertiary amine or aminoether, any
perfluoropolyether, and any hydrofluoropolyether.”  

EPA received numerous comments on the definition, particularly in
regards to Subpart OO-Suppliers of Industrial GHGs.  For example, some
commenters argued that the proposed definition of fluorinated GHGs was
too broad because it would include nonvolatile materials that could not
be emitted to the atmosphere.  More specifically, one commenter
suggested establishing a lower vapor pressure limit for fluorinated GHGs
(heat transfer fluids) of 400 Pa (0.004 bar, or three mm Hg absolute) at
25 C.  

 In response to comments, in the 2009 final Part 98 (74 FR 56260), EPA
finalized the following definition of fluorinated GHG: “Fluorinated
GHG means sulfur hexafluoride (SF6), nitrogen trifluoride (NF3), and any
fluorocarbon except for controlled substances as defined at 40 CFR part
82, subpart A and substances with vapor pressures of less than 1 mm of
Hg absolute at 25 degrees C.  With these exceptions, “fluorinated
GHG” includes but is not limited to any hydrofluorocarbon, any
perfluorocarbon, any fully fluorinated linear, branched or cyclic
alkane, ether, tertiary amine or aminoether, any perfluoropolyether, and
any hydrofluoropolyether.”  As EPA stated in the preamble to the final
rule, “This modification ensures that non-volatile fluorocarbons such
as fluoropolymers are excluded from reporting requirements, while
requiring reporting of fluorocarbons (as well as SF6 and NF3) that could
reasonably be expected to be emitted to the atmosphere” (74 FR 56348,
October 30, 2009).    

EPA proposed the subpart I definition for HTFs, which included the term
“fluorinated GHG,” in an April 12, 2010 Federal Register notice (75
FR 18652).  In a December 1, 2010 final rule “Mandatory Reporting of
Greenhouse Gases: Additional Sources of Fluorinated GHGs” (75 FR
74775), EPA finalized a definition for HTFs that was substantially
similar to the definition in the April 2010 proposed rule.  

Following publication of the final rule, 3M Company (3M) sought
reconsideration of the reporting requirements for fluorinated GHGs used
as HTFs under subpart I.  Specifically, in its Petition for
Reconsideration dated January 28, 2011 (available in docket
EPA-HQ-OAR-2009-0927), 3M stated that “…as currently written the
reporting requirements for heat transfer fluids will exclude a
significant portion of fluorinated GHGs used as heat transfer fluids. 
Thus, the GHG emissions associated with heat transfer fluids will not be
accurately reported under the rule.”  Further, 3M stated, “By tying
the reporting requirements for heat transfer fluids to the definition of
a fluorinated GHG under §98.6 in Subpart A, the scope of Subpart I’s
reporting requirements are limited to those heat transfer fluids that
have vapor pressures of >1 mmHg at 25 degrees C.  Although 3M
understands the reasons behind the vapor pressure threshold in the
general definition of a fluorinated GHG, the same rationale should not
apply to heat transfer fluids.  Heat transfer fluids are used at
elevated temperatures and pressures, and as a result the vapor pressure
of these materials at 1 mm Hg absolute T 25 degrees C is not predicative
of emissions.  Heat transfer fluids are used through a broad range of
boiling points and are routinely lost from systems primarily through
mechanical leaks but also from evaporative loss.  Once emitted from a
system, the fate of heat transfer fluids is primarily the atmosphere.”
   

In addition to the concern that the rule will result in “dramatic
under reporting of heat transfer fluid use and emissions,” 3M also
raised the concern that “although all the heat transfer fluids that
have relatively low global warming potentials will be required to be
reported as GHGs, a substantial percentage of heat transfer fluids that
have global warming potentials in the range of 10,000 times that of CO2
will be exempt from reporting requirements.”  Consequently, 3M argued,
“the rule will likely lead to a migration toward use of exempt
compounds and an increase in GHG emissions from the sector.”

To address the problem, 3M suggested that subpart I should be amended to
specify that for reporting requirements under subpart I, the vapor
pressure cutoff in the general definition of fluorinated GHG does not
apply to HTFs.  

In finalizing the HTF provisions in subpart I, EPA did not intend to
exclude a significant portion of fluorocarbon HTFs that can enter the
atmosphere; any such exclusion was inadvertent.  Given the high
temperatures in which HTFs may be used, EPA believes that such fluids
are able to enter the atmosphere even when their vapor pressures at 25
degrees C (77 degrees F) are low.  This is because the vapor pressures
of substances increase as their temperatures increase, and HTFs with low
vapor pressures are likely to be used in high-temperature applications. 
(Vapor pressure is an indicator of the rapidity with which a substance
evaporates.)  For example, an HTF with a vapor pressure of about 0.2 mm
Hg at 25 degrees C might be used at a temperature of 140 degrees C for
heat transfer applications, where it may have a vapor pressure of over
80 mm Hg.  Similarly, an HTF with a vapor pressure of about 0.1 mm Hg at
25 degrees C might be used for vapor phase soldering at a temperature
above its boiling point.  Under these conditions, all of the material is
in the vapor phase.  Supporting technical information is available in
the docket (EPA-HQ-OAR-2011-0512).   

EPA understands that at any particular temperature, an HTF with a low
vapor pressure at 25 degrees C is likely to evaporate more slowly than
an HTF with a higher vapor pressure at 25 degrees C.  Nevertheless, if
the temperature is high, evaporation will occur.  

EPA views data on emissions of HTFs as an important component in
improving future efforts to characterize GHG emissions from the
electronics manufacturing sector.  EPA believes that the changes being
proposed today will ensure that all fluorinated HTFs used in electronics
manufacturing are appropriately monitored and reported under subpart I. 

In this action, EPA is proposing that the definition of HTFs in subpart
I be revised to read as follows: “Fluorinated heat transfer fluids
means fluorinated GHGs used for temperature control, device testing,
cleaning substrate surfaces and other parts, and soldering in certain
types of electronics manufacturing production processes.  For
fluorinated heat transfer fluids under this subpart I, the lower vapor
pressure limit of 1 mm of Hg in absolute at 25 degrees C in the
definition of “fluorinated greenhouse gas” in 40 CFR 98.6 shall not
apply.  Fluorinated heat transfer fluids used in the electronics
manufacturing sector include, but are not limited to,
perfluoropolyethers, perfluoroalkanes, perfluoroethers, tertiary
perfluoroamines, and perfluorocyclic ethers.”  

The effect of making the vapor pressure cut-off portion of the
definition of fluorinated GHGs inapplicable to fluorinated HTFs under
subpart I would be to subject  emissions from fluorinated HTFs that have
vapor pressures less than one mm of Hg absolute at 25 degrees C to the
reporting requirements.  Consequently, EPA would receive valuable
emissions information on the full range of volatile fluorinated HTFs
used in electronics manufacturing.  

The purpose of the Mandatory Reporting Rule is to collect accurate
facility-specific GHG emissions data for use in developing future GHG
policies and programs.  For this reason, EPA believes that the
definition of HTFs being proposed today is prudent and appropriate
because it will provide EPA with comprehensive information on emissions
of fluorinated HTFs.  Considering the simple mass balance methodology
required for reporting emissions of fluorinated HTFs in subpart I, the
potential value of this information justifies a comprehensive
definition.  If some HTFs (or HTFs in some currently included
applications) are found to have very low emission rates, this
information will itself be valuable for informing future GHG policies. 
However, given that HTFs are capable of entering the atmosphere at the
temperatures where they are used, any conclusion that the emissions of
some HTFs are low must be supported by actual measurements.  

EPA considered including a modified vapor pressure limit in the proposed
definition of HTF.  One approach we considered was to adopt a vapor
pressure limit associated with a particular temperature higher than 25
degrees C.  The goal of such a limit would be to require reporting of
those HTFs that may readily enter the vapor phase in their current and
potential future applications.  However, we believe that today’s
proposed, application-based definition achieves this goal more simply
and effectively than would a definition that includes a vapor pressure
limit associated with a particular temperature higher than 25 degrees C.
 First, given the breadth of conditions under which HTFs are used
currently in the electronics industry, as well as the rapidity of
technological change within this industry, it would be difficult to
specify an appropriate upper-limit temperature to which to link the
vapor pressure.  Some applications occur at very high temperatures, and
those temperatures could conceivably rise in the future.  Second, such a
limit, if not linked to particular HTF applications, could include
fluorinated chemicals that are used exclusively in low-temperature
applications where they would not quickly enter the atmosphere if
released, such as certain lubricants or oils.  Third, the major
application of HTFs is for process cooling.  In this application, as
discussed above, HTFs with lower vapor pressures at a particular
temperature are likely to be used at higher temperatures.  This is a
systematic relationship that almost guarantees that the HTF will be
capable of volatilizing at the temperature of use.  Similar
relationships are likely to hold in other applications where viscosity
or boiling point is a concern, e.g., thermal shock testing.  Finally,
other applications, such as substrate cleaning or vapor phase soldering,
occur when the material is in the vapor phase.  Any upper-bound
temperature linked to a vapor pressure would have to fall above the
temperatures where vapor phase soldering occurs. The proposed definition
achieves the same goal much more directly by including the applications
“soldering,” “temperature control,” “device testing,” and
“cleaning substrate surfaces.” 

Another approach we considered was to require reporting only of HTFs
that achieve a particular vapor pressure (e.g., 1 mm Hg absolute) at
their maximum temperature of use, where the maximum temperature of use
could vary from facility to facility or even application to application
within a facility.  This approach would explicitly focus monitoring and
reporting on those HTFs and applications where volatilization could
occur.  However, because the coverage of particular chemicals would
depend on their maximum temperature of use within a particular facility
or application, this approach would be significantly more difficult to
implement and enforce than the proposed, application-based definition. 
Facilities would be required to investigate the temperatures at which
each HTF is used and to distinguish between low- and high-temperature
applications of the same HTF in developing emissions estimates.  The
proposed approach, in contrast, would clearly define the applicability
of the rule and would enable facilities (and EPA) to rely on
facility-wide mass-balances to estimate emissions of particular
chemicals.  

EPA does not intend for its definition of HTFs to include greases or
lubricants such as those used in vacuum pump applications because such
applications do not typically occur at temperatures at which the
lubricants would volatilize.  EPA does not believe that the current or
proposed definitions include such lubricants.  However, EPA requests
comment on whether the definition should be amended to explicitly
exclude lubrication or other applications.  To address situations in
which a particular chemical may be used in both HTF and non-HTF
applications, EPA also requests comment on whether we should give
reporters flexibility to report under 40 CFR 98.93(h) either a
chemical’s emissions from all applications or its emissions from only
the applications included in the HTF definition.  This would give
facilities the option to avoid maintaining a separate supply of the
chemical for purposes of tracking HTF emissions, as would otherwise be
required for the mass-balance calculation.  Emissions from the non-HTF
applications would presumably make up a small fraction of the total. 

The narrow exception to the vapor pressure cutoff would only apply to
fluorinated HTFs used in the electronics manufacturing industry; EPA
continues to believe that the vapor pressure cutoff is appropriate to
maintain in the definition of fluorinated GHG in 40 CFR 82 subpart A
(e.g., for purposes of the industrial gas supply provisions at subpart
OO).  EPA is not aware of other fluorocarbon applications in which the
vapor pressure of the fluorocarbon falls below 1 millimeter of Hg at 25
degrees C but typically rises significantly above it at the temperature
of use.   

In addition, EPA is also proposing four other minor amendments to the
regulatory text related to fluorinated HTFs.  First, in the definition
of HTF (40 CFR 98.98), EPA is proposing to add the phrase “but not
limited to” before listing examples of fluorinated HTFs.  Electronics
manufacturing is an innovative and quickly evolving industry in which
new chemicals are frequently adopted.  EPA is proposing this change to
ensure that potential future alternatives are covered.  Second, also in
the definition of HTFs (40 CFR 98.98), EPA is proposing to delete the
last sentence (“Electronics manufacturers may also use these same
fluorinated chemicals to clean substrate surfaces or other parts”) and
move the concept of cleaning substrates surfaces or other parts to the
first sentence.  EPA is proposing this change to improve readability of
the definition.  Third, EPA is proposing minor revisions throughout the
subpart I regulatory text to clarify the use of the terms fluorinated
GHGs and fluorinated HTFs (e.g., referring to fluorinated HTFs rather
than fluorinated GHGs used as HTFs).  For example, in instances where
EPA used the term “fluorinated GHG used as heat transfer fluids,”
EPA is proposing to use “fluorinated heat transfer fluids.”  Where
EPA refers to HTFs, EPA does not intend the full definition of
fluorinated GHGs (as defined in subpart A) to apply.  And last, in 40
CFR 98.92(a)(5), under GHGs to report, EPA is proposing to revise the
clause “fluorinated GHG emitted from heat transfer use” to read
“emissions of fluorinated heat transfer fluids.”  EPA is proposing
this change to clarify that emissions of fluorinated HTFs, not just
fluorinated GHGs, are required to be reported under subpart I.  In
addition, EPA is proposing the change to clarify the Agency’s
intention that emissions from HTFs can occur through all phases of the
equipment’s lifetime, including installation, use, servicing, and
disposal.  Under subpart I, all of those emissions of HTFs should be
calculated and reported.    

EPA does not anticipate an increase in burden resulting from these
proposed changes because this action is clarifying the intent of the
requirements finalized in subpart I.  In finalizing the reporting
requirements for fluorinated HTFs, EPA did not intend to exclude
fluorocarbons that can enter the atmosphere under the conditions in
which HTFs are used in the electronics manufacturing industry.  EPA’s
burden estimates were based on reporting of all fluorinated HTFs;
therefore, the clarification of intent does not impose additional burden
on reporters.

EPA requests comment on the proposed amendments to the HTF provisions of
subpart I.  In particular, EPA requests comment whether the proposed
definition effectively captures fluorinated HTFs used in electronics
manufacturing (i.e., whether any type of fluorinated HTFs other than
those included in the proposed definition are currently being used or
are anticipated to be used in the future for electronics manufacturing).
 EPA also requests comment on whether any other conforming changes need
to be made.  

EPA plans to address the comments on these proposed amendments and
publish the final amendments to subpart I before the end of 2011. 
Therefore, EPA requests comment on whether to require electronics
manufacturing facilities to estimate and report 2011 emissions in 2012
of the HTFs that would be newly included in the scope of subpart I if
today’s proposed rule were finalized.  Specifically, EPA requests
comment on whether information collected as part of routine business
practices, such as records of HTF stocks, disbursements, and
acquisitions, could be used to estimate 2011 emissions to be reported in
2012.  If it is not feasible to estimate HTF emissions in 2011 for
substances that are currently excluded from reporting using information
collected as part of routine business practices, EPA requests detailed
information illustrating why it is not feasible.   

C.  Subpart W – Petroleum and Natural Gas Systems 

EPA is proposing several technical clarifications and amendments to
subpart W to address issues raised during the first year of promulgation
of the rule in response to petitions submitted to EPA for
reconsideration, as well as clarifications to specified provisions in
the rule to ensure consistency with subpart W, and across all subparts,
where appropriate.  In addition, several technical corrections are
proposed to clarify provisions that were either erroneous or unclear to
reporters. 

The following section describes EPA’s proposed amendments.  We first
discuss the proposed amendments related to field-level reporting in the
onshore petroleum and natural gas production section, since this
proposed amendment affects multiple emissions sources (well completions,
well workovers, well venting for liquids unloading, and onshore storage
tanks) and also affects many sections of the rule (e.g., calculation,
monitoring and quality assurance/quality control (QA/QC), and the data
reporting requirements).  Following the discussion for onshore
production, we discuss the proposed amendments to the Definition of the
Source Category (40 CFR 98.230), GHG’s to Report (40 CFR 98.232),
Calculating GHG Emissions (40 CFR 98.233), Monitoring and QA/QC
Requirements (40 CFR 98.234), Data Reporting Requirements (40 CFR
98.236) and Records to be Retained (40 CFR 98.237) under subpart W.

Sub-basin Category for Onshore Petroleum and Natural Gas Production. 
EPA has received several requests to reconsider the use of a field-level
measurement plan for emission sources (mainly monitoring of GHGs from
well unloading, well completions, and well workovers) that require one
measurement per field as designated by the U.S. Energy Information
Administration (EIA) Field Code Master List (FCML).  Onshore petroleum
and natural gas production reporters have expressed concerns over the
use of this field designation and proposed that a sub-basin category be
assigned instead of a field designation to take measurements. 
Specifically, petitioners indicated that EPA has not clarified how
reporting entities are supposed to map wells to a particular field. 
They contested that there are no coordinates provided in the EIA FCML
2008.  They also suggested there is no formal way to designate
appropriate field names and the rule does not have a mechanism to deal
with wells that are not in a recognized field in the EIA Master List. 
Mapping wells to the proper field is central to compliance with the
rule, they assert, because the rule requires aggregation of information
by field for the different emissions sources.  To address these
concerns, industry petitioned EPA to replace the field-level approach
with a “sub-basin category” approach.  	In general, EPA continues to
believe that the field-level designation is workable, although perhaps
not the only means of obtaining representative emissions estimates.  EPA
has determined that the EIA field codes are developed using field names
that operators provide and agree on with States, which is finally
provided by the States to the EIA.  Therefore, EPA believes that
operators can determine the EIA field they are in using the EIA field
codes.  EPA also agrees that the 2010 final rule did not state a clear
mechanism to address wells in fields that were not included in the EIA
FCML.  However, EPA has determined that this is not an acute problem. 
EPA has analyzed the EIA FCML for several years and found that the
changes in the database from year to year are not significant.  For
example, there were only 30 changes in field definitions between 2007
and 2008  of the total 64,454 fields in the database.  Similar numbers
result from comparing 2006 with 2007 (170 changes in field definition of
a total 63,873 fields in the database) and comparing 2006 with 2005 (44
changes in field definition of a total 63,356 fields in the database). 
The changes include both the revision of some field names as well as new
additions.

In this action we are proposing an alternative approach to replace
“field-level” with “sub-basin categories.” EPA considered, but
is not proposing at this time modifications to the current field level
reporting method that would address the outstanding concerns raised by
industry.  Specifically, EPA considered an amendment that would allow
reporters to use a temporary field name when submitting reports to EPA
in instances where a well does not fall within a designated EIA field
code.  This alternative approach would include a provision for reporters
to report a preliminary field name where a field has not been formally
designated by the State and as such may not yet be included in the EIA
FCML. These preliminary fields entered by the reporter would be
annotated in the final report to EPA and would be flagged in the data
system for further follow up to determine the final field name
designated by the State.  Because States operate on different schedules
for which final determinations are made on field designation requests,
reporters would be required to certify with official documentation
submitted to EPA upon each reporting period on the status of their field
designation request.  Under this alternate approach, for field
designations that are made prior to the next reporting date, reporters
should confirm the field designation with official documentation during
the next submission of their emission report to EPA.  This proposed
method would address concerns raised by industry about fields not yet
included in the EIA FCML.      

In addition, EPA is considering but did not propose a provision that
would delineate how reporters would determine appropriate field names
for wells for which the designated field is unknown due to unclear
location or coordinates of the well.  Under such a provision, reporters
would determine the EIA FCML field for a given well  by determining the
well coordinates and follow the procedures outlined in the 2008 EIA FCML
or most approximate year’s documentation that accompanies the EIA FCML
field list which outlines the method for matching up well coordinates
with field names.  Although EPA is proposing an alternative means to
calculate and report emissions based on a sub-basin category, we are
seeking comment on this approach to modify the current field-level
calculation and reporting requirements for utilizing the EIA FCML for
sampling.  Although EPA maintains that the current field level
calculation and reporting requirements are feasible and provide
representative emissions estimates (with an amendment to clarify how to
address non-designated fields), EPA is proposing an alternative
sub-basin approach that we believe also achieves an appropriate level of
representativeness.  Please see Economic Impact Analysis Memorandum in
Docket ID EPA-HQ-OAR-2001-0512.  This proposed  sub-basin category
classification would provide similar quality data as the EIA FCML
designation but believes will also address some of the questions and
concerns regarding current implementation of the field-level approach. 

The foundation of the proposed sub-basin approach is defining a
sub-basin category through the use of a county level designation and the
distinction of the type of hydrocarbon formation.  The various
hydrocarbon formations can be grouped into four categories:
conventional, coal bed methane, tight formations, and shale.  For
example, wells producing coal bed methane from formation “X” with
wellhead coordinates within county “A” would be one sub-basin
category.  Further, wells producing from tight formation “Y” with
wellhead coordinates within county “A” would be a second sub-basin
category.  In the event that a specific county includes more than one
formation (e.g.,. coal bed methane and tight sands), then the reporter
would use the most specific designation (e.g., coal bed methane). 

With this basic formulation of sub-basin category, EPA has determined
that it is necessary to provide a second level of classification to get
a representative emissions profile of emissions sources.  For example,
the emissions from well completions or hydraulic fracturing can vary by
several multiples within the same producing formation because of
different fracture zones and fracture extent.  Similarly, well liquids
unloading emissions can vary widely because of different well dimensions
and liquid accumulation.  EPA further notes that the activity of
emissions sources are highly concentrated within certain counties and
formation types.  For example, of the 3,143 counties in the United
States, there are only 54 counties that had any form of well completion
in year 2010.  In such a case, where 25,000 well completions are
concentrated in 54 counties, a single measurement from a sub-basin
category, may not be sufficiently representative. 

Therefore, to obtain a sufficient number of data points to be able to
characterize the variability in the emissions profile, EPA is proposing
a measurement plan that uses some operational criteria to generate more
than one sample per sub-basin category for specific emissions sources. 
Specifically, EPA is proposing the use of pressure ranges for liquids
unloading measurements, because the volume of gas released during an
unloading is related to the wellhead pressure.  For example, reporters
would take one measurement per pressure range within a sub-basin
category.  An example of pressure ranges is 0-25 psig, >25-60 psig,
>60-110 psig, >110-200 psig, and 200 psig and above.  These pressure
ranges were developed based on an analysis that reviewed well data from
the HPDI© database which determined the optimal pressure ranges that
also minimize variability of a single data point as a representation of
that pressure range.  For more information on this analysis, please see
the Technical Support Document for this proposed rulemaking in the
docket.  

The rationale for applying these pressure ranges is that wells generally
have more liquids unloading problems when they are flowing at low
pressures and lower velocities.  Hence, it is reasonable to provide more
ranges in the lower pressure spectrum.  EPA expects to see few wells
over 200 psig that necessitate liquids unloading to atmospheric
pressure.  For well completions and workovers, EPA is proposing to
divide the population of wells between vertical and horizontal wells, as
defined in proposed amended 40 CFR 98.238, and then using a graduated
number of measurements per number of wells completed or worked over in
these categories.  For example, one measurement per 25 wells with
hydraulic fracture, two measurements per 50 wells with hydraulic
fracture, three measurements per 100 wells with hydraulic fracture, and
four measurements per 200 or more wells with hydraulic fracture.  EPA
understands that there are many operational factors that impact the
magnitude of emissions from well hydraulic fracture completions and
workovers and therefore is proposing more than one measurement where
there is a larger number of wells in the sub-basin category. 

Source Category Definitions.  In general, we are proposing several
amendments to the source category definitions to clarify the boundaries
between the different industry segments.  The proposed amendments below
seek merely to clarify coverage in the rule and were not intended to
change who is required to report within and across the industry
segments.

Onshore Petroleum and Natural Gas Production.  We are proposing several
amendments to the definition for the onshore petroleum and natural gas
production (also referred to as onshore production) industry segment in
40 CFR 98.230(a)(2).  EPA received feedback from reporters on the
finalized definition for the onshore production industry segment on
November 30, 2010 (see 75 FR 74489) requesting clarification on the term
“associated with a well-pad.”   Specifically, reporters requested
clarification on what the term “associated with a well-pad” meant in
the context of the boundaries of the onshore production industry
segment. Reporters stated that there is unclear demarcation between
equipment that are considered part of the onshore production industry
segment and equipment that are considered part of the onshore natural
gas processing industry segment.  

To address concerns on the meaning of ”associated with a well-pad”,
EPA is first proposing to revise the term itself to state that the
onshore production industry segment includes that equipment that is
“on a single well-pad or associated with a single well-pad.”  EPA
has determined that equipment located on a single well-pad is considered
part of the onshore production industry segment irrespective of the
hydrocarbon streams that it is  handling.  For example, a separator
located on a well-pad that handles hydrocarbon streams from multiple
well-pads would be considered to be part of the onshore production
industry segment, i.e. equipment that is not located on a well-pad would
be considered to be associated with a well-pad.  Also, hydrocarbon
streams from multiple wellheads located on a single well-pad is
considered to be a single hydrocarbon stream from that well-pad.   

In addition, EPA is proposing to clarify in the onshore production
industry segment definition that dehydrators that are on a single
well-pad or associated with a single well-pad are included as types of
equipment that is considered part of this segment.  Following
promulgation of subpart W in November 2010, EPA received several
questions from the reporting community requesting clarification on
whether or not dehydrators associated with a single well-pad would be a
part of the industry segment.  It was EPA’s intent that these
dehydrators that are on a well-pad or associated with a single well-pad
be considered part of the onshore production industry segment.  EPA also
received similar requests for clarification on whether or not storage
vessels, not necessarily the entire storage facility, were also
considered part of the onshore production industry segment.  To address
these concerns, EPA is proposing to clarify in the definition that both
dehydrators and storage vessels are included in the equipment list that
are considered part of the onshore production industry segment. 
Finally, EPA proposes to clarify that Enhanced Oil Recovery (EOR) that
use either CO2 or natural gas are a part of the source category.  The
equipment located on a well-pad is part of the onshore production
industry segment irrespective of the hydrocarbon streams located on a
well-pad.

Onshore Natural Gas Processing.  EPA is proposing several clarifications
to the onshore natural gas processing industry segment definition in 40
CFR 98.230(a)(3).  By letter dated January 31, 2011, the Gas Processors
Association (GPA), CEC/AXPC, and API, all expressed concerns with
overlap between the onshore production, onshore natural gas processing,
and onshore natural gas transmission industry segments.   API stated
that “The definitions of the industry categories ‘onshore oil and
gas production’ and ‘natural gas processing’ do not provide a
clear line between onshore oil and gas production, gas
gathering/collection and booster stations, and natural gas processing
facilities.”  The letter stated “API is particularly concerned that
the final rule could be interpreted to include gathering and boosting
stations in the processing sector, despite EPA’s stated intent to
exclude gathering and boosting stations from coverage at this time.” 
Industry raised concerns that boosting stations would be covered under
the finalized natural gas processing industry segment definition because
they typically have processes that require removal of liquids for
operation of specific equipment that boost gas pressure.  For example,
scrubbers are used upstream of compressors to take out any liquids for
optimal operation of the compression equipment.  However, the presence
of scrubbers in and of itself should not result in the facility being
defined as a processing facility.     

To address the concerns with boundaries between industry segments, we
are proposing several revisions to clarify our intent.  First we are
proposing to strike the term “and recovers” from the first sentence
in order to more clearly characterize the unique activities performed at
the processing plant.  Processing plants extract heavy hydrocarbons and
non hydrocarbon gases from the gaseous phase of an inlet feed to the
plant.  By inclusion of the term “recovers” in the industry segment
definition, the natural gas processing plant definition may have been
incorrectly interpreted to bring in other types of processes that were
not intended to be covered.  

We are also proposing to clarify that this industry segment includes one
or a combination of the following three processes: separation of natural
gas liquids (NGLs) from natural gas, separation of non-methane gases
from produced natural gas, or separation of NGLs into one or more
component mixtures.  This proposed revision would clarify that the
natural gas processing industry segment differs from what typically
happens at boosting stations in that natural gas processing plants
typically perform one or more of these processes, whereas boosting
stations do not. 

We are also proposing a clarification on what separation means by
stating that separation means one or more of the following processes:
forced extraction of natural gas liquids, sulfur and carbon dioxide
removal, fractionation of NGLs, or the capture of CO2 separated from
natural gas streams.

We are proposing to strike the term “this industry segment does not
include reporting of emissions from gathering lines and boosting
stations” because the edits proposed above clarify what “onshore
natural gas processing” means and therefore it is unnecessary to
discuss that which is excluded.  Further, if we had decided to maintain
the “gathering lines and boosting” stations in the rule, EPA would
have to propose and finalize a definition of the term “gathering line
and boosting” station, which EPA has previously noted we intend to
consider in a future rulemaking (75 FR 74468). 

Finally we are proposing to strike the term “facility” and replace
it with the term “plant” as “facility” has a specific definition
in 40 CFR 98.6 that was not intended here.  A natural gas processing
plant may be located at a facility that also contains other source
categories covered by 40 CFR Part 98. 

Onshore Natural Gas Transmission Compression.  EPA is proposing several
clarifications to the onshore natural gas transmission compression
industry segment definition in 40 CFR 98.230(a)(4).  As noted earlier,
by letter dated January 31, 2011, API, CEC/AXPC, and GPA raised their
concerns that the boundaries between the onshore production, onshore
natural gas processing, and onshore natural gas transmission compression
industry segment boundaries were unclear based on the provisions in the
November 30, 2010 final rule. 

First, we are proposing to strike the term “at elevated pressure”
because it was not clear what “elevated pressure” meant.  For
example, elevated with respect to what baseline?  Based on questions
received on the definition for transmission compressor stations, we have
proposed to clearly define transmission pipelines using a widely
accepted designation for what is a transmission pipeline, avoiding the
need to retain the language of “elevated pressure”.  We are
proposing to define in 40 CFR 98.238 that a transmission pipeline means
a Federal Energy Regulatory Commission (FERC) rate-regulated interstate
pipeline, a state rate-regulated intrastate pipeline, or a pipeline that
falls under the “Hinshaw Exemption” as referenced in the Natural Gas
Act. 

Next, we are proposing to clarify the end points between which a natural
gas transmission compression facility would move natural gas. 
Specifically, we are proposing to explicitly state that natural gas
transmission compression facilities not only move natural gas from
production fields or gas processing plants, but also move natural gas
coming from other transmission compressors.  In addition, we are
proposing to explicitly state that natural gas transmission compression
facilities may move natural gas into not only distribution pipelines,
but also into liquefied natural gas storage or into underground storage.


We are also proposing to strike the term “natural gas dehydration”
from the industry segment definition because this term does not
represent a unique characteristic to facilities with natural gas
transmission compression.   We believe that deleting this term from the
definition of the natural gas transmission compression industry segment,
will result in this industry segment definition being more
representative and accurate.  Finally, as described above under onshore
natural gas processing, we are proposing to strike the reference to
“gathering lines and boosting stations” and “facility.”  

Natural Gas Distribution.  EPA is proposing several amendments to the
natural gas distribution industry segment definition to further clarify
its intent.  First, we are proposing in 40 CFR 98.230(a)(8) to eliminate
the term “city gate station” and add the term “meter-regulating
station”.  The term “city gate”, was used in the 2010 final rule
because it was believed to be widely used throughout the natural gas
distribution industry.  However, since publication, we have learned that
the term can have several meanings and the interpretation of what is a
“city gate” station may vary among potential reporters.  By letter
dated March 2, 2011 from the American Gas Association, it was stated
that “[t]he term `city gate´ is widely used in the industry, but
unfortunately it means different things to different companies.  It can
mean the place where an LDC takes custody of natural gas from the
upstream supplier (either directly from a producer or from an interstate
pipeline company).  The term `city gate´ is also used by some to refer
to the place where natural gas is conveyed into a lower pressure
distribution system for a town or city – either directly from the
upstream supplier (producer or interstate pipeline) or from the LDC’s
own intrastate high pressure transmission pipelines.  Some companies do
not use the term `city gate´ to refer to the situation where natural
gas goes from the company’s own transmission pipes to one of its
distribution systems.  Instead, these companies may use other terms such
as `district regulator´ or `metering and regulating stations´, or
`M&R´ equipment, and these terms also can have varying meanings.”  

Further, subpart A provides a definition for “city gate”, which was
intended to apply to subpart NN and is based on financial custody
transfer.  Whereas the connotation of the term city gate as defined in
subpart A works sufficiently for subpart NN, it has created confusion
for subpart W and does not clearly identify the types of facilities EPA
intended to cover.  The amendments that EPA is proposing are designed to
more clearly portray EPA’s intent using language readily
understandable to industry. 

First, we are proposing to strike the parenthetical term “(not
interstate transmission pipelines or intrastate transmission
pipelines).”  The parenthetical was deemed  unnecessary because EPA is
proposing to add a definition for “distribution pipeline” in 40 CFR
98.238 that clarifies that “distribution pipelines” are only those
designated as such by the Pipeline and Hazardous Material Safety
Administration (PHMSA).  Next, we are proposing to replace the term
“city gate” with “meter-regulating” station.  Because of the
wide range of views in industry on the meaning of the term “city
gate” EPA is proposing to remove the term “city gate” from subpart
W and replace it with a term that reflects the types of activities
occurring at the stations of interest.  Specifically, we are proposing
to add a definition for the term “meter-regulating station” in 40
CFR 98.238 to mean, “An above ground station that meters the flow
rate, regulates the pressure, or both, of natural gas in a natural gas
distribution facility.  This does not include customer meters, customer
regulators, or farm taps”. With this change, EPA intends to clarify a
key concept in the natural gas distribution segment definition, but does
not intend to change who is actually covered by the rule’s
requirements.          

EPA is proposing to strike the terms “excluding customer meters” and
“physically deliver natural gas to end users” because the proposed
definition for “meter-regulator” stations already addresses this
exclusion. 

 Finally, we are proposing to clarify in the industry segment definition
that we are only seeking for LDCs that are within a single state,
consistent with the definition for LDCs in subpart NN. 

Greenhouse Gases to Report. We are proposing several amendments to the
subpart W provisions on the greenhouse gases that must be reported.   

We are proposing to amend 40 CFR 98.232(c) to clarify that the equipment
listed in 98.232(c)(1) thru (22) are for equipment on a single well-pad
or associated with a single well-pad in order to make the language
consistent with the proposed changes to the onshore production industry
segment definition in 40 CFR 98.230(a)(2) described above.   

We are proposing to amend 40 CFR 98.232(i) by replacing the term
“custody transfer city gate station” with the term
“transmission-distribution transfer station” and replacing the term
“non-custody transfer station” with the term “metering-regulating
station.”  EPA is proposing this amendment to clarify that the sources
covered be consistent with the proposed terms for the natural gas
distribution industry segment in 40 CFR 98.230(a)(8).  We are also
proposing to amend the source types by removing the text “Customer
meters are excluded.” The exclusion is already covered in both the
industry segment definition and in the definition of
“metering-regulating station” provided in 40 CFR 98.238 and does not
provide added clarity in this context.  Next, we are proposing to strike
40 CFR 98.232(j) in order to address concerns raised that the inclusion
of this provision resulted in confusion amongst reporters as they were
unsure how this provision aligned with the flare emissions that are
captured under the applicable emissions source calculations throughout
40 CFR 98.233.  In addition to the proposal to strike 40 CFR 98.232(j),
we are proposing to revise the introductory sentences to 40 CFR
98.232(e), (f), (g), (h) and (i) to clarify that N2O emissions, which
are the primary GHG emission from flaring, are also required to be
reported under these industry segments.  This proposed amendment also
clarifies that flare emissions must only be calculated where “flare
stacks” are either specifically identified in a specific industry
segment (e.g., onshore natural gas processing) or where an emissions
source that is covered in an industry segment is routed to a flare
(e.g., centrifugal compressors under onshore natural gas transmission). 


Finally, we are proposing to further clarify in 40 CFR 98.232(k) that
the onshore production and natural gas distribution industry segments
are to report their combustion emissions under subpart W, while the
remaining industry segments are to report their combustion emissions
under subpart C of part 98.

Calculating Greenhouse Gas Emissions.  We are proposing several
clarifications, corrections, and amendments throughout 40 CFR 98.233. 

Natural Gas Pneumatic Device Venting.   

EPA is proposing to revise Equation W-1 in 40 CFR 98.233(a) by adding 40
CFR 98.233(a)(3) that allows the type of pneumatic devices to be
determined using engineering estimation based on best available
information.  The proposed amendment for pneumatic devices was in
response to questions received about how to determine whether a
pneumatic device is high bleed or low bleed and the unanticipated burden
for industry if they would have to measure the bleed rate of all
pneumatic devices in order to determine how to characterize each
pneumatic device. 

EPA is also proposing to amend Equation W-1, to include a parameter
“T” that estimates the total number of hours the devices were
operational.  Previously, this equation assumed that all natural gas
pneumatic devices were operational all year, which would overestimate
the emissions where the pneumatic devices operate less than a full year.
 Overall, we are proposing these amendments to Equation W-1 to more
accurately reflect operating conditions for natural gas pneumatic device
venting.  Furthermore, EPA is clarifying in the definition for
“GHGi” that compositions in 40 CFR 98.233(u) may be used for the
onshore petroleum and natural gas production, onshore natural gas
transmission compression, and underground natural gas storage industry
segments.   

In addition, with respect to the pneumatic device venting category, we
are proposing in 40 CFR 98.236(c)(1)(iv) to clarify that emissions
should be reported collectively for all high bleed pneumatic devices,
then separately for all intermittent bleed pneumatic devices, and
separately for all low bleed pneumatic devices.  The 2010 final rule
stated merely “report emissions collectively”.  The proposed
amendment is consistent with how data are collected and emissions
calculated.  

Natural Gas Driven Pneumatic Pump Venting.  

We are proposing to amend Equation W-2 in 40 CFR 98.233(c), which is
used for calculating GHG emissions from natural gas pneumatic pump
venting, to include a parameter “T” that estimates the total amount
of hours the pumps were operational.  Previously, this equation assumed
that all natural gas pneumatic pumps were operational all year, which
would overestimate the emissions where the pneumatic devices operate
less than a full year.  We are proposing this amendment to Equation W-2
to more accurately reflect operating conditions for natural gas
pneumatic pump venting.   

Acid Gas Removal Vents.  We are proposing to amend the calculation for
estimating CO2 emissions from acid gas removal vents in Equation W-4 in
40 CFR 98.233(d).  EPA notes that the equation in the 2010 final rule is
an approximation and works well when the amount of CO2 in gas is
relatively low, such as 1 percent.  However, the error rate in the
estimate increases significantly as the amount of CO2 in gas increases. 
Therefore, EPA is proposing a new equation, which uses the exact same
input parameters and thus will not result in any additional burden to
reporters, but will improve the quality of the information submitted to
EPA.  

We are also proposing to amend 40 CFR 98.233(d)(1) to specify that the
use of CEMS is required if a CO2 concentration monitor and volumetric
flow rate monitor are installed.  This amendment was made to clarify
what conditions must be met to satisfy the subpart C: Stationary
Combustion Tier 4 calculation requirement for Acid Gas Removal vents and
to make the requirements consistent in subpart W where use of CEMS is
required.

In 40 CFR 98.236(c)(3) we are proposing to clarify that reporting of CO2
content should reflect the annual average of the measurements undertaken
in 40 CFR 98.233(d).  The 2010 final rule was not clear on whether or
not to aggregate the measurements, and if so, how. 

Dehydrator Vents.  EPA is proposing several amendments to the provisions
in 40 CFR 98.233(e) for calculating GHGs from dehydrator vents.  First,
we are proposing to clarify that gases other than natural gas, such as
nitrogen, flash gas from the flash tanks, or dry gas from the absorber, 
that are used as stripping gases satisfy the requirements stated in 40
CFR 98.233(e)(1) introductory language.  The final rule explicitly
stated that natural gas was the gas considered to be the stripping gas. 
We are proposing this amendment to more accurately reflect operating
conditions for glycol dehydrators in which gases other than natural gas
are used as stripping gases. 

We are also proposing to amend 40 CFR 98.233(e)(6) to clarify that GHG
mass emissions from glycol dehydrators are to be calculated from
volumetric GHG emissions using calculations in 40 CFR 98.233(v).  In
addition, we are proposing to clarify that only for dehydrators that use
desiccant should GHG volumetric and mass emissions be calculated using
paragraphs 40 CFR 98.233(u) and 98.233(v).   We are proposing this
amendment to account for calculation methodology 1 and 2, 40 CFR
98.233(e)(1) – (e)(3), that calculates total GHGi volumetric emissions
in standard cubic feet and will only need conversion to GHG mass
emissions using 40 CFR 98.233(v).  

With respect to the data reporting requirements, we are proposing to
clarify the requirement to report vented and flared emissions
individually.  In the 2010 final rule, EPA intended that vented
emissions be reported as one value, and flared emissions as a separate
value.  However, because these were entered in the same sub-paragraph,
40 CFR 98.236(c)(4)(i)(J), there was some ambiguity as to the
aggregation for reporting.  Therefore, EPA is proposing to create
separate reporting requirements for vented and flared emissions.  A
similar amendment is proposed for 40 CFR 98.236(c)(4)(ii)(D).

Also for dehydrators, EPA is proposing to clarify that in specifying
whether any vent gas controls have been used, the owners or operators
should report which vent gas controls were used. 

Well Venting for Liquids Unloadings.  First, we are proposing to revise
40 CFR 98.233(f) methodology 1, methodology 2, and methodology 3 such
that sampling would be done in a sub-basin category as opposed to the
field level as described earlier in Section II.C.  of this preamble
(Sub-basin Category for Onshore Petroleum and Natural Gas Production).  

In the technical corrections rule, EPA proposed several technical
corrections to the provisions in 40 CFR 98.233(f) including corrections
to Equation W-8, W-9, and their respective definitions.  In today’s
action, we are proposing additional revisions to Equations W-8 and W-9
and their respective definitions.  Because both proposed actions affect
the same paragraph of the rule, for clarity the part 98 amendatory
language at the end of this preamble contain the full set of revisions
from both proposed actions.  The changes proposed today are explained
below in this preamble.   

First we are proposing to revise Equation W-8 by correcting the
definition for parameter Ea,n to be Es,n to accurately reflect that the
calculated emissions should be in standard conditions and not actual
conditions.  The proposed revision from actual conditions to standard
conditions was made to be more uniform in approach to calculate
emissions.   The parameters in Equation W-8 have been made applicable to
each venting instance, q, and for each well, p, in a pressure grouping
and sub-basin category.  These changes are notational amendments that
correct the summation operation.  Next, we are proposing to amend the
definition for “SFR” which is the average sales flowrate to state
that the average sales flow rate of gas is to be obtained at standard
conditions, and also that Equation W-33 may be used to convert the sales
flow rate from actual to standard conditions.  In addition, the
definition for parameter WDwp has been clarified to mean the distance
between the lowest packer to the bottom of the well.  We are also
proposing to remove 40 CFR 98.233(f)(2)(i) to remove redundancy with 40
CFR 98.233(f)(4).  As stated previously, we are proposing to amend
Equation W-9 in the same manner as Equation W-8: by revising the
definition for “Ea,n” to accurately state that the definition should
result in standard conditions, thus “Es,n”, and by revising the
definition for SFR to state that the average sales flow rate is to be
calculated at standard conditions using Equation W-33; and the
parameters, where applicable, have been made applicable to each venting
event, q for each well, p, in a pressure grouping and sub-basin category
to correct the summation.  Finally, we are proposing to amend Equation
W-8 and W-9 to account for a change in aggregation from field level to
sub-basin category for reporting.  

For Calculation Method 1, where a representative measurement is taken
from one well unloading and then applied to all other wells of a similar
type, EPA is defining the categorization of “similar types” by five
pressure ranges and three tubing diameters.  The pressure ranges were
optimized using HPDI well counts in 5 psig pressure increments from zero
gauge pressure to 200 psig.  The fifth “unbounded” pressure range is
“greater than 200 psig,” which EPA believes will have very few well
liquids unloading venting to the atmosphere.  The three tubing diameter
ranges, equal or less than 1 inch, greater than 1 inch and equal or less
than 2 inch, and greater than 2 inch, were derived from gas well tubing
suppliers’ specifications.  The relevancy of these pressure ranges and
tubing diameter ranges is that liquids unloading venting is dependent on
both the shut-in pressure of the reservoir (shut-in by liquids
accumulation) and velocity of gas pushing liquids up the tubing, which
is a function of tubing diameter.  

Finally, in the data reporting requirements in 40 CFR 98.236(c)(5), we
are proposing to make a harmonizing change, consistent with the
amendments described above in (Sub-basin Category for Onshore Petroleum
and Natural Gas Production), that reporting should be for each well
tubing diameter grouping and pressure grouping within each sub-basin
category.  

Gas Well Venting During Completions and Workovers from Hydraulic
Fracturing.  We are proposing several amendments to 40 CFR 98.233(g) to
account for the proposed change in aggregation from field level to
sub-basin category for taking measurements.  For example, we are
replacing the term “field” with “sub-basin and well type
combination” in the definitions and clarifying that the GHG emissions
are determined for each sub-basin and well type combination.  For
further discussion on the proposed changes from field level calculations
and reporting to sub-basin category, please refer to Section II.C of
this preamble (Sub-basin Category for Onshore Petroleum and Natural Gas
Production).

We are also proposing to revise equation W-10 by including a provision
to account for the time period in which we believe normal production of
a well would be established.  In this action, we are revising equation
W-10 by defining a parameter, FRM, which would represent the ratio of
emissions (FRP) to the average 30 day production from the well
immediately following hydraulic fracturing (PRp).  The emissions, FRp,
which in the final rule as the average flow rate in cubic feet per hour
converted to standard conditions, are calculated using W-11A and W-11B. 
FRM is calculated using the newly assigned Equation W-12.  We believe
that this proposed revision will more accurately represent the
production flow from a well immediately following a well or completion
using hydraulic fracturing and will more accurately represent when a
completion or workover ends and when normal production begins.  Finally,
in Equation W-10, EPA is proposing to add the parameter W, which is the
number of wells completed or worked over using hydraulic fracturing in a
sub-basin and well type combination, and, where appropriate, made the
parameters applicable to each well p.  This amendment corrects the
summation operator to make it mathematically accurate. 

  EPA also added Equation W-11C, which allows reporters to determine
whether the well flow rate of gas during venting to the atmosphere or a
flare (i.e. FRWp), is sonic or sub-sonic flow.  Thus, reporters can
determine whether to use Equation W-11A, which is for sub-sonic flow, or
Equation W-11B, which is for sonic flow.

We are also proposing several minor edits to 40 CFR 98.233(g)(3) and 40
CFR 98.233(g)(5) to clarify that all requirements in 40 CFR 98.233(g)
apply to gas well venting during completions and workovers from
hydraulic fracturing, consistent with the emission source name of “Gas
well venting during completions and workovers from hydraulic
fracturing”. 

In 40 CFR 98.233(g)(3) we are also proposing to delete the reference to
how to calculate the volume of recovered completion or workover gas. 
The first sentence in that paragraph is already clear that company
records may be used, therefore the second sentence does not provide any
additional information and is duplicative.

We are proposing several harmonizing changes to the data reporting
requirements for this emissions source.  We are proposing to indicate
that reporting is required for each “sub-basin category” and well
type (horizontal or vertical).  We are also proposing to clarify that
reporting of reduced emissions completions for both well completions and
workovers is required.  Although this information is required to be
collected for both well completions and well workovers, EPA
inadvertently omitted the reporting requirement for reduced emissions
completions for well workovers. 

Also in 40 CFR 98.236, we are proposing to clarify that reporters are
only required to count the number of workovers that flare or vent gas to
the atmosphere.  There is no reporting requirement for workovers that do
not flare or vent gas.

Gas Well Venting During Completions and Workovers Without Hydraulic
Fracturing.  In this section we are proposing to strike the term “well
workovers not involving hydraulic fracturing” from the introductory
text in paragraph (h) because it was repetitive.  

Second we are proposing to replace the term “field” used in the
definition for the parameter “Nwo” and “f” for the same reasons
stated in Section II.C.  of this preamble (Sub-basin Category for
Onshore Petroleum and Natural Gas Production). 

Finally, EPA is proposing to amend the summation operator in Equation
W-13 to make it mathematically accurate.  This includes making specific
parameters in Equation W-13 applicable to each well completion, p.

Blowdown Vent Stacks. In a previous action we proposed amendments to the
introductory sentences to 40 CFR 98.233(i).  In this action, based on
additional questions received during implementation of subpart W, we are
proposing to further clarify the types of blowdowns that EPA intended to
cover.  First, we are proposing to delete “to atmosphere” because
not every blowdown will result in the blowdown chamber being brought to
atmospheric pressure.  Operators often release only part of the gas in
the blowdown chamber and maintain it at low pressure.  It was always
EPA’s intent to cover these types of “blowdowns” and thus we are
proposing to delete “to atmosphere”.  Further we are clarifying that
we only intend to cover the types of blowdowns typically tracked by
operators for planned maintenance or emergency shutdowns.  EPA had
earlier proposed to exclude emergency shutdowns in a previous action. 
However, EPA has since been informed that operators track emergency
shutdowns already.  Therefore, EPA is proposing to require emergency
shutdowns to be reported.  In addition, we did not intend to capture
blowdowns that are not typically tracked by operators, such as pressure
release valve releases designed to keep equipment under safe operating
mode.   

EPA has also considered other factors that could impact emissions from
blowdowns, for example compressibility.  We have considered accounting
for gas compressibility but have not proposed this because we believe
that the effort in adjusting for a compressibility factor outweighs the
benefits in terms of increased accuracy.  EPA seeks comments on why such
an allowance should be provided and how to standardize this option so
that those who choose to use it all do so in the same way.

Also in this action, we are proposing to revise the numbering of
Equation W-14b and include an additional Equation, W-14b that will take
into account that a chamber may not be blown down to atmospheric
pressure, and will allow facilities the option of tracking blowdowns by
each occurrence by blowdown volume.  It has come to EPA’s attention
that some facilities may log blowdowns at a facility by individual
blowdown occurrence.  To enable facilities to retain their current
tracking system, we are proposing to add an option for calculating
blowdown emissions by equipment type.  This option for tracking
blowdowns would not impact data quality.  Harmonizing changes in 40 CFR
98.236(c)(7) are being proposed to account for these amendments. 

Lastly, we are proposing to include a default composition for the
natural gas transmission industry segment, and for the LNG storage and
underground storage segments.  EPA received feedback from industry that
a default composition of 95 percent  methane and 1 percent CO2 was a
representative breakdown of the gas composition at these types of
facilities while limiting burden and should be acceptable.  EPA agrees
that a default composition of 95 percent methane and 1 percent CO2 is
appropriate because the composition of natural gas is monitored by
transmission compression companies and regulated by FERC.  

Onshore Production Storage Tanks.  EPA is proposing to replace the term
“field” in 40 CFR 98.233(j)(1)(vii)(B), 40 CFR 98.233(j)(1)(vii)(C),
and 40 CFR 98.233(j)(3)(i)with “sub-basin category” consistent with
the proposed amendments described in Section II.C, (Sub-basin Category
for Onshore Petroleum and Natural Gas Production), of this preamble.  We
are also proposing to clarify this level of reporting in the data
reporting requirements in 40 CFR 98.236(c)(8). 

Also in the data reporting requirements, we are proposing to clarify the
reporting requirement in 40 CFR 98.236(c)(8)(i), 98.236(c)(8)(ii) and
98.236(c)(8)(iii) that reporters must report vented, flared, and
recovered emissions individually for Calculation Methodology 1 and 2. 
This is consistent with the calculation requirements.  

Transmission Storage Tanks.  We are proposing to revise 40 CFR 98.233(k)
to include an additional provision such that reporters would now have
the option of directly measuring the transmission storage tanks while
bypassing an initial screening with the optical gas imaging instrument. 
 EPA received feedback from industry that some owners and operators
would prefer to simply measure the tank annually without having to be
required to screen the tank vapors with a camera first.  We agree that
allowing facilities to directly measure the emissions, without first
requiring leak detection, does not compromise data quality, but could
enable facilities to meet the requirements of the rule with lower
burden.  Therefore, in this action, EPA is proposing to allow operators
to either screen their tanks first by using the optical gas imaging
instrument for 5 continuous minutes and if a leak is detected, measure
the leak according to the provisions in 40 CFR 98.234 consistent with
the 2010 final rule, or measure the tank vent vapors for 5 minutes using
either a flow meter, calibrated bag, or high volume sampler according to
the provisions outlined in 40 CFR 98.234.  

Finally, with respect to the data reporting requirements in 40 CFR
98.236(c)(9), as described further above, we are proposing to clarify
the separate reporting requirements for vented and flared emissions.

Well Testing Venting and Flaring.  EPA is proposing 

In amendments to the data reporting requirements in 40 CFR
98.236(c)(10).  Specifically, we are proposing to add a reporting
requirement for the emissions of the flaring gas collectively.  This is
consistent with other proposed clarifications to report  flared
emissions separately.  

EPA is considering, and has not proposed, using the production rate to
estimate volume of emission from gas wells that produce dry gas.  EPA is
soliciting comments on this suggested provision for gas wells. 

EPA has received several requests to exclude the well testing venting
and flaring emissions source from the rule.  Industry has informed EPA
that this source has very little, if any, emissions because the well
testing is almost exclusively performed in a closed system using a
“test separator”, which industry has stated would result in zero
emissions. 

EPA has reviewed this request and in general, EPA continues to believe
that well testing venting and flaring is a relevant source in the
onshore petroleum and natural gas production industry segment.  In
addition, EPA has determined that during well testing, some states allow
companies to flare sour gas for a maximum of 72 or 144 hours.  EPA has
concluded that this approach would result in emissions from this source
that should be reported under this rule.  If, however, for some reason
reporters do not have any emissions from this source (for e.g., states
do not allow venting or flaring from well testing), they would report
zero emissions.  

Thus, EPA is retaining well testing venting and flaring in the rule. 
However, EPA is seeking comment on how to reduce or eliminate burden in
cases where companies verify that zero emissions are associated with
this potential source, such as when a closed loop system is employed.

Associated Gas Venting and Flaring.  EPA is proposing to revise 40 CFR
98.233(m) to replace the term “field” with the term “sub-basin
category” for the same reasons outlined in Section II.C.  (Sub-basin
Category for Onshore Petroleum and Natural Gas Production)of this
preamble. 

Flare Stack Emissions.  We are proposing two amendments in 40 CFR
98.233(n)(2) to clarify how to determine gas compositions for
hydrocarbon streams going to flare.  First, we are proposing to amend 40
CFR 98.233(n)(2)(ii) to clarify that reporters must use the GHG mole
percent in feed natural gas for all streams for onshore natural gas
processing plants that solely fractionate a liquid stream.  EPA is
proposing this amendment to address lack of clarity in the final
provisions which did not explicitly state how natural gas processing
plants which only fractionate liquid streams would determine their gas
compositions.  We are also proposing to clarify in 40 CFR
98.233(n)(2)(iii) that methane, in addition to ethane, propane, butane,
pentane-plus and mixed light hydrocarbons, should be accounted for when
the stream going to the flare is a hydrocarbon product stream.  This
proposed technical correction, to add methane, ensures that the
paragraph 40 CFR 98.233(n)(2)(iii)  is consistent with the equation.  

In addition, we are proposing to clarify the summation operator in W-21
to make it mathematically correct.  We are also clarifying that source
types in 40 CFR 98.233 that send emissions to a flare must determine
volumetric flow rate, parameter “Va”,  in Equation W-19 through
W-20, at actual conditions. 

We are also proposing to clarify that the volume of gas sent to the
flare should be calculated in actual conditions.  This is consistent
with other proposed changes throughout this revision that clarify the
use of actual versus standard conditions.

In addition, we are proposing to allow facilities the option to use a
continuous emissions monitoring system (CEMS) to estimate GHG emissions
from flares.  EPA received questions as to why CEMS were allowed for use
for AGR vents, for example, but not for flares.  We did not intend to
unnecessarily limit the measurement options for flares, and therefore
are proposing to add the option to use CEMS. 

The proposed text clarifies that the use of CEMS is required if a CO2
concentration monitor and volumetric flow rate monitor are installed and
that optionally a user may install a CO2 concentration monitor and
volumetric flow rate monitor to be eligible to use the Tier 4
methodology.  When CEMS are used to calculate emissions for flare stacks
the use of equations W-19 to W-21 would no longer apply.  With the
relatively high quantity of unburned methane in the emissions from
flares, EPA has identified that it is not appropriate to use the CH4
calculation methodology in subpart C as most flared gases will not be
fuels listed in Table C-1 of subpart C. EPA is seeking comment on what
form an equation should take that would calculate CH4 and N2O for flares
that are monitored by CEMS.  One option is to calculate the CH4 by
multiplying the concentration of CO2 measured by the CEMS by the
fraction of CH4 that was not combusted as determined by flare
efficiency.

In the data reporting requirements in 40 CFR 98.236(c)(12) we are
proposing to add reporting requirements consistent with the calculation
requirements in Equations W-19 through W-21.  Specifically, we are
proposing to add reporting of uncombusted CH4, combusted and uncombusted
CO2 and combustion-related N2O emissions.  The proposed amendments
ensure consistency across the calculation, monitoring and reporting
requirements. 

Centrifugal Compressor Venting.  Consistent with other clarifications
throughout this proposed rule, we are proposing to clarify in the
definition for the term MTm in Equation W-24 that flow measurements
should be determined in standard cubic feet per hour.  

Leak Detection and Leaker Emission Factors.  

We are proposing to revise 40 CFR 98.233(q)(8) to remove the term
“city gate stations at custody transfer” and replace with
“transmission-distribution transfer stations”  for the reasons
described earlier in Section II.C of this preamble.  We are also
proposing to remove the term “meters and regulators” and replace
with above ground “metering-regulating stations”.  The term
“meter-regulating” is a term that we are proposing to define in this
action, as described earlier in Section II.C of this preamble. 

The revisions to terminology for natural gas distribution facilities
have been proposed to clearly identify who is covered under the
distribution segment of subpart W, and the sources for which leak
detection and measurement are required and those sources for which an
emission factor can be used.  Based on feedback received from industry,
there may be concerns that the emission factors developed at the
transmission-distribution transfer stations are not representative of
emissions at other above ground metering-regulating stations.  Although
we are not proposing changes to the approach for applying emission
factors to above ground metering-regulating stations in this action, we
are seeking comment on alternative approaches, or data that may be used,
for determining emissions factors for above ground metering-regulating
stations.  Based on comments received, EPA may consider future
amendments to the rule.   

In a separate action, (76 FR 37300)  EPA is proposing to expand the
final BAMM provisions to cover all facilities subject to subpart W, and
allow reporters the option to use best available monitoring methods
(BAMM) for all of 2011 without being required to submit a request for
approval to the Administrator.  For natural gas distribution facilities
at transmission-distribution transfer stations, this would allow
facilities to estimate the number of equipment leaks and the equipment
sources themselves using BAMM as provided in the rule, along with the
total time the component was found leaking and operational, as outlined
in Equation W—30.  This emission factor could then be used for other
above ground metering-regulating stations within the facility boundary. 
   

EPA is proposing to clarify the summation operator in W-30 to make it
mathematically correct.  This clarification includes amending x to be
the total number of each equipment leak source and adding Tp, which is
the total time the component p was found leaking and operational.  We
are proposing to revise the parameter GHGi.  For industry segments
listed in 98.230 (a)(4) and (a)(5), GHGi has been revised to 0.974 for
CH4 and 1.0 × 10-2 for CO2.  For industry segments listed in (a)(6) and
(a)(7), GHGi equals 1 for CH4 and 0 for CO2.  For industry segments
listed in (a)(8), GHGi equals 1 for CH4 and 1.1×10-2 CO2 (See Technical
Support Document Memo (TSD)in Docket ID EPA-HQ-OAR-2011-0512 for further
details).

Next we are proposing two amendments in 40 CFR 98.236(c)(15).  We are
proposing to amend the reporting requirements in 40 CFR
98.236(c)(15)(i)(C) to clarify that owners or operators must report CH4
emissions collectively by equipment type and CO2 emissions collectively
by equipment type.  The calculation methodologies in 40 CFR 98.233(q),
as finalized in the rule, require reporters to calculate CH4 emissions
and CO2 emissions separately per source with equipment leaks.  We are
proposing this amendment to clarify that applicable reporters must
report the CH4 emissions collectively by equipment type and CO2
emissions collectively by equipment type.  We are also proposing to
correct the reporting requirement in 40 CFR 98.236(c)(15)(ii)(A) to not
include onshore natural gas processing.  This source category is not
required to use population emission factors.  This amendment is
associated with the amendment to Equation W-31 in 40 CFR 98.233(r)
discussed in Calculating Greenhouse Gas Emissions.

Population Count and Emission Factors.  We are proposing several
amendments in 40 CFR 98.233(r).  First we are proposing to amend the
population emission factor definition in equation W-31 by replacing the
term “non-custody transfer city-gate” with above grade
“metering-regulating station” for the reason stated above in this
preamble.  We are also clarifying that the count in equation W-31
applies to the number of “meter/regulator runs” at all
“metering-regulating stations” combined.  

We are also proposing to amend the term “count” in W-31 as follows
to elaborate and clarify how each industry segment should count the
total number of equipment/components.  In that same equation, we are
also proposing to revise the definition for GHGi by referring to 40 CFR
98.233(u) and deleting the composition specified for each industry
segment.  

Next, EPA is proposing to amend 40 CFR 98.233(r)(2)(i) to  explicitly
state how meters and piping are to be counted.  Table 1-B of the 2010
final rule was developed using activity data from the 1996 EPA/Gas
Research Institute Study (1996 EPA/GRI Study), Methane Emissions from
the U.S. Natural Gas Industry.  For all major equipment that are not
specifically listed, the 1996 EPA/GRI Study categorized all components
at a well-pad under the meters/piping category.  Therefore, owners or
operators should use one count of meters/piping per well-pad.  

Further, consistent with proposed amendments described above, EPA is
proposing to amend 40 CFR 98.233(r)(6)(ii) by referring to
“metering-regulating stations” in place of “city gate” and to
clarify that the emission factor for meter/regulator runs at all
metering-regulating stations in equation W-32 is based on leak detection
performed at “transmission-distribution transfer stations”.  EPA is
also amending 40 CFR 98.233(r)(6)(i) to clarify that below grade meters
and regulators apply to below grade “metering-regulation stations”.

Lastly, we are proposing revisions to equation W-32 that include
revisions to the definitions for EF, Es,i, and “Count” again to
clarify the terminology change away from “custody transfer” to above
ground “metering-regulating” stations.  We are also proposing the
inclusion of a conversion factor to convert to hourly emissions. 
Consequently, we are proposing to amend the conversion in Equation W-32
in 40 CFR 98.233(r) so that the equation yields an EF in cubic feet per
meter per hour to be used in Equation W-31 for above ground
metering-regulating stations.  Finally, the summation operator has been
removed in Equation W-32 because Es,i represents annual volumetric GHGi
emissions at all T-D transfer stations, making the summation operator
redundant.     

In addition to the proposed calculation amendments described above, we
are also proposing to replace the term “field” with “sub-basin
category” in the reporting for onshore production, consistent with the
proposed change to sub-basin calculation and reporting. 

Volumetric Emissions.  We are proposing to amend 40 CFR 98.233(t) to
clarify that reporters should use actual temperature and pressure and
adjust to standard conditions.  The phrase “by converting actual
temperature and pressure of natural gas emissions to standard
temperature and pressure of natural gas” was deleted because it is
redundant.

GHG Volumetric Emissions.  We are proposing to amend 40 CFR 98.233(u) to
include 95 percent methane/1 percent CO2 default gas composition for the
natural gas transmissions industry segment, along with the LNG storage
and underground storage industry segments.  Again, as described above,
EPA agrees that a default composition of  95 percent methane and 1
percent CO2 is appropriate because the composition of natural gas is
monitored consistently and regulated by FERC.  

We are also proposing to strike the reference to the term “field” in
40 CFR 98.233(u) and replace with “sub-basin category” for the
reasons outlined in Section II.C.  of this preamble (Sub-Basin Category
Reporting for Onshore Petroleum and Natural Gas Production).  

We are also proposing to clarify that the GHG mole fraction that is
determined without using a continuous gas analyzer may be determined
using an annual average instead of the most recent gas composition based
on available analysis in a sub-basin entity. 

GHG Mass Emissions.  We are proposing to clarify in the definitions to
the equation W-36 that the equation applies to N2O emissions as well. 
N2O emissions are calculated from stationary combustion and flares, and
the proposed edit is necessary to convert the mass emissions of N2O to
carbon dioxide equivalents of gas.  EOR injection pump blowdown.  We are
proposing to clarify in the equation that only CO2 emissions are
calculated.  The variables Massc,i has been changed to Massc,CO2, and
GHGi has been changed to GHGCO2.

Onshore Production and Distribution Combustion Emissions.  In a previous
action, EPA proposed several revisions to 40 CFR 98.233(z) including
corrections to Equations W-39 and 40.  In this action, we are proposing
additional amendments to clarify when owners or operators of onshore
production and distribution facilities must use the methods in 40 CFR
subpart C to calculate combustion-related emissions and when they must
use the methods in 40 CFR 98.233(z) to calculate combustion-related
emissions.  We are proposing to clarify that facilities using subpart C
to calculate emissions are not limited to the use of tier 1, but rather
may use any tier.  Regardless of the tier used, the facility must follow
the corresponding calculation, monitoring and reporting requirements of
that tier. 

We are also proposing to amend the requirements for units combusting
field gas or process vent gas.  The 2010 final rule required the use of
a continuous flow meter, if present.  Use of a continuous flow meter
would have necessitated calibration requirements per 40 CFR 98.3(i). 
These calibration requirements were disproportionately burdensome for
these relatively small disperse units, particularly given that
facilities that currently do not have a flow meter in place could use
company records.  In this action, we are proposing to amend the
requirements to allow the use of company records for this equipment.   

Onshore Production and Distribution Equipment Threshold for Internal
Combustion Equipment.  In letters dating January 31, 2011 and March 5,
2011 from API and AGA, respectively EPA received petitions to reconsider
an exemption for internal combustion engines similar to that which was
in the final subpart W rule (75 FR 74458, November 30, 2010) for
external combustion engines.  These requests from the onshore petroleum
and natural gas production and natural gas distribution reporters were
to provide respite for reporting of emissions from internal combustion
equipment that are brought in temporarily for maintenance and
construction.  Some reporters have requested complete exemption such
that combustion equipment that fall below a specific threshold would be
exempt from reporting. 

EPA considered, but decided not to propose an exemption for reporting
for internal combustion engines.  EPA decided not to propose amendments
because data currently are not available to sufficiently characterize
these upstream emissions.  For example, the volume of fuel consumed,
especially at wellhead natural gas compressors, is not being monitored
and only limited data, voluntarily reported, are available through the
Energy Information Administration. 

Although EPA has decided not to propose a threshold due to lack of
availability of a comprehensive data source from which to develop
policy, we acknowledge that there is potentially small internal
combustion equipment outside of compressors.  In considering a potential
equipment threshold for non-compressor internal combustion engines, EPA
collected and reviewed data on the size ranges of small, portable
internal combustion engines that may be brought to a wellhead for
periodic maintenance and construction.  Such equipment would include,
for example, electric generators for arc welding, electric generators
powering portable flood-lighting, and electrical generators or gasoline
engines powering air compressors (for sand blasting or pneumatic tools).
 For lighting, the industrial generators were almost exclusively below
12 horsepower (hp), with the highest found being 13.9 hp.  For welding
machines, we assumed that they would use standard portable generators,
since specific information on these types of machines was scarce.  Most
portable industrial generators are rated between 15-40 hp, with the
largest one found being 67 hp. EPA determined that 130 horsepower
(double the largest size found) would exclude virtually all small
portable or stationary internal combustion engines, but is much smaller
than the 5 mmBtu/hour exclusion for external combustion sources and
equates to about 1 mmBtu/hour.  EPA is seeking comments on whether a 1
mmBtu/ hour equipment threshold for internal combustion engines that are
not driven by natural gas is reasonable.  We also seek comment on
EPA’s position that combustion-related emissions at compressors should
not be excluded from reporting, regardless of size and where EPA can
find reliable estimates of natural gas consumption.

EPA is proposing to clarify the summation operator in Equation W-39 to
make it mathematically correct.  In addition, EPA is proposing to
clarify in Equation W-40 that N2O mass emissions are calculated by
changing the parameter N2O to Masss,N2O.

 In specific, EPA is soliciting comments  as to why emissions from
specific internal combustion related equipment should not be reported
including the size of the equipment that should be excluded along with
supporting data. 

Monitoring and QA/QC Requirements.  We are proposing several amendments
to the monitoring and QA/QC requirements in 40 CFR 98.234. 

First, we are proposing to amend the language in 40 CFR 98.234(a)(1) by
first removing and reserving the text in 40 CFR 98.234(a)(4) and
combining it with 40 CFR 98.234(a)(1),   thus resulting in one
consolidated paragraph.  We are also proposing to state explicitly that
video recordings are not required under subpart W.  As noted in the
Response to Comments to the 2010 final rule, EPA did not intend to
require retention of a video recording of the leak detection using
optical gas imaging instruments for reporting to EPA under subpart W of
the greenhouse gas reporting rule.  However, some of the references to
the Alternate Work Practice suggested that EPA intended that facilities
retain these records onsite.   

Next, we are proposing to amend the language in 40 CFR 98.234(a)(2) to
state that Method 21 compliant instruments may be used to monitor
inaccessible emissions sources.  This amendment increases flexibility in
monitoring requirements and reduces the burden on the industry, without
compromising data quality. 

Further, based on questions raised by industry, we are proposing to
amend 40 CFR 98.234(a)(5) by revising the acoustic leak detection device
provisions to use a different model of acoustic detector, one that does
not have a through-valve leakage correlation, thereby allowing leakage
to be measured by other methods if a leak is found.   

However, EPA is proposing to clarify that not all types of acoustic
detectors are allowed.  In particular the “gun” type instrument that
is aimed at the equipment from a distance to detect the acoustic signal
of leakage is not an allowable instrument.  This type cannot distinguish
between external leakage to the atmosphere from internal, through-valve
leakage, which is the objective for specifying this device.  EPA is
proposing to further specify that the “stethoscope” type acoustic
detector that senses through valve leakage when put in contact with the
valve body, but does not have the leakage estimating correlations, may
be used.

We are also proposing editorial revisions in 40 CFR 98.234(c) for
calibrated bagging to specify that those using the calibrated bag for
sampling, must ensure that the emissions must be at a temperature below
that which the bag manufacturer specifies for safe handling. 

Data Reporting Requirements.  We are proposing several amendments and
clarifications throughout 40 CFR 98.236 in order to address questions
received about how data should be reported.  Many of the data reporting
requirements were lacking clarity with respect to the level of
reporting.  Based on the questions received, as well as EPA’s
experience gained in developing the electronic GHG reporting tool
(e-GGRT), which provided EPA a better understanding of the clarity
necessary in the data reporting requirements, EPA is proposing the
following changes.

In cases where technical amendments were already proposed for individual
emissions sources above, EPA has described the corresponding proposed
amendments to the reporting requirements along with the technical
amendments.  This section outlines any remaining proposed amendments to
the data reporting requirements not already described above.

First we are proposing to clarify the data reporting requirements for
offshore petroleum and natural gas production facilities in 40 CFR
98.236(b).  Specifically, the 2010 final rule was not clear in terms of
which gases were required to be reported and the data elements for
reporting.  Consistent with the calculation requirements, we are
proposing to clarify that facilities containing the offshore petroleum
and natural gas production segment would be required to report emissions
of CH4, CO2, and N2O as applicable to the source type (in metric tons
CO2e per year at standard conditions) individually for all the emissions
source types listed in the most recent BOEMRE study. 

Next, in the introductory paragraph for 40 CFR 98.236(c) we are
proposing to clarify that vented emissions should be reported separately
from flared emissions.  We have specified which source types require
separate calculation of flared emissions, but EPA is taking comment on
whether any source types that have process gas routed to flares were
excluded from having specific reporting requirements established for
flares. 

We are proposing to make changes to the data reporting requirements for
local distribution companies, consistent with the proposed amendments to
40 CFR 98.230(a)(8).  Specifically, we are proposing to replace
“custody transfer” with “transmission-distribution transfer”
station and replace “non-custody transfer” with “above ground
metering-regulating station.”  In addition, we are proposing to
require the reporting of counts and emissions of both above grade and
below grade stations for each of metering-regulating stations and
“transmission-distribution transfer stations”.

Finally, EPA seeks some basic information on average API gravity of the
hydrocarbon liquids produced, gas to oil ratio, and low pressure
separator pressure per sub-basin entity.  It is EPA’s understanding
that his information is already known to reporters.  EPA will use these
facility sub-basin characteristics to characterize other emissions
sources across different sub-basins.”

Records that must be retained.  EPA is proposing to add the following
recordkeeping requirement: “The records required under §98.3(g)(2)(i)
shall include an explanation of how company records, engineering
estimation, or best available information are used to calculate each
applicable parameter under this subpart.”  While EPA believes this
requirement is already included in 40 CFR 98.3(g)(2)(i) where the
records for “The GHG emissions calculations and methods used”
requirement is made, EPA believes that adding this statement to the
recordkeeping requirements in subpart W will provide facilities with
further clarity on the records they are required to keep.  This
clarification is intended to make clear that stating company records,
engineering estimation, or best available information were used is not
enough to satisfy the requirement in 40 CFR 98.3(g)(2)(i).  This
requirement is intended to parallel a similar requirement for subpart C
specified in 40 CFR 98.34(f) and referenced in 40 CFR 98.37.

Definitions.  We are proposing to amend, and in some cases, add
definitions to 40 CFR 98.238 to further clarify rule requirements.

Associated With a Single Well-Pad.  We are proposing to add a definition
for “associated with a single well-pad” to clearly demarcate the
boundary of onshore production.  EPA proposes that the association be
defined by the hydrocarbon stream from a single well-pad.  The
association with a single well-pad ends where the stream from a single
well-pad is combined with streams from one or more additional single
well-pads, where the point of combination is located off that single
well-pad.  In addition, we are stating that this definition does not
include storage and condensate tanks that are located downstream of the
point of combination.  For gas contained in crude oil or condensate
flowing under pressure off a single well-pad to a gas-liquid separator
or tank, or comingled with flow from other well-pads, 40 CFR 98.233(j)
requires reporting of the gas content that may be released from the oil
or condensate in an atmospheric pressure fixed roof storage tank.  We
have determined that the conditions of the pressurized oil or condensate
(i.e. gravity, pressure, temperature, flow rate) are commonly known by
the well owner/operator, and the amount of gas that may be released from
the oil or condensate with a pressure reduction can be determined most
appropriately by the well owner/operator.  

Distribution Pipeline.  EPA is proposing to include a definition for
distribution pipelines to add clarity on its intent on coverage for the
natural gas distribution industry segment.  We are proposing to use a
widely accepted definition for distribution pipelines, specifically,
those designated as such by the Pipeline and Hazardous Material Safety
Administration (PHMSA).

Facility With Respect to Natural Gas Distribution.  EPA is proposing to
revise the definition for natural gas distribution by replacing the term
“metering stations, and regulating” with the term
“metering-regulating”.  EPA is proposing to include a definition for
the term above ground “metering-regulating station” to clarify where
leak detection and monitoring is required in the 2010 final rule.  

Farm Taps.  EPA is proposing to revise the definition for farm taps in
40 CFR 98.238 by striking the unnecessary phrase “The gas may or may
not be metered, but always does not pass through a city gate station.”

Flare.  We are proposing to add a definition of flare specific for
subpart W to address questions received during implementation about what
constitutes a flare.  The proposed definition clarifies that a flare may
be either at ground level or elevated and uses an open or enclosed flame
to combust waste gases without energy recovery.  This definition for
subpart W is intended to be inclusive of devices that combust waste
gases without energy recovery.  This broad, all-inclusive definition for
Subpart W is necessitated by the wide variety of waste gas combustion
devices that are or may be used in the different segments of Subpart W,
all for the same purpose and having the same effect of combustion
emissions of hydrocarbon gases. 

Forced Extraction of Natural Gas Liquids.  We are proposing to add a
definition for forced extraction to restrict it to specific processes. 
EPA determined that it was necessary to develop this more precise
definition because many industry questions pointed to the confusion
between processing plants, gas gathering stations and wellheads, where
similar equipment and processes are conducted as at some, but not all,
processing plants that EPA determined should be subject to this rule. 
Those similar processes.  These processes in and of themselves do not
make a facility a “processing plant.” Furthermore, the Oil & Gas
Journal annual survey of gas processing plants is primarily focused on
those that fractionate, leaving out known, large gas plants that
separate NGLs or condition gas, but do not fractionate, and are clearly
not gathering booster stations.  The key principle that EPA is
attempting to clarify through this definition is the separation of
heavier hydrocarbons in the vapor phase of natural gas delivered to a
plant, excluding the simple gravity separation of liquids entrained in
the gas.  This principle is “forced extraction”, as defined here. 

Horizontal Well.  With the change from field level reporting to
sub-basin category, EPA is proposing to add a distinction for
calculating emissions from horizontal wells and vertical wells.  We are
proposing to define horizontal well to mean a well bore that has a
planned deviation from primarily vertical to a primarily horizontal
inclination or declination tracking in parallel with and through the
target formation.

ith >0.1 millidarcy permeability, and unconventional with ≤0.1
millidarcy permeability shale, coal seam, and other tight reservoir
rock, all of which are unconventional with ≤0.1 millidarcy
permeability . Unconventional wells producing from formations
categorized in two or more types are considered shale for a combination
of “shale and coal”, “shale and other tight”, or “shale, coal
and other tight”; and are considered as coal for combinations of
“coal and other tight". 

Transmission-Distribution (TD) transfer station.  EPA is proposing to
add a definition for Transmission Distribution (TD) transfer station to
define what was previously termed “custody transfer” in the final
rule.  It was not EPA’s intent for the term “custody transfer” to
be defined in the context of ownership of gas transfer.  EPA believes
the new definition may be universally applied to designate which
“metering-regulating stations” are classified as
“transmission-distribution transfer stations”.  All covered stations
in the distribution segment will be collectively referred to as
“metering-regulation stations” but the subset that require leak
detection are “transmission-distribution transfer stations.” EPA was
notified of concerns from industry that defining a transmission
distribution transfer station without a threshold would include numerous
small TD transfer stations that would otherwise not have been required
to perform leak surveys.  EPA has not included any thresholds in the
proposal but we are taking comment on what an appropriate threshold
would be to exclude these smaller transfer stations.  Such a threshold
should exempt stations with low throughputs or low emissions.  Any
threshold should be readily verifiable and be readily applied to all
stations.  Potential options for a threshold include using the inlet
pressure, the design or actual flow rate of the station, or other
parameters directly related to the emissions from the station.  Any
suggested changes should include a discussion of how many stations would
be exempted from leak detection and how many would still require leak
detection.  Such an exemption would not preclude a station from
reporting, it would only mean that leak detection is not required at
that station.  The stations that fall below the select threshold would
still be included for evaluation against the 25,000mtCO2e threshold
through the application of an emissions factor.  Natural gas
distribution facilities that do not have any TD transfer stations above
the threshold, would use a factor to determine their emissions and
compare those emissions against the 25,000 mtCO2e threshold.  

Transmission Pipeline.  We are proposing to add a definition for
transmission pipeline.  Transmission pipelines are clearly designated as
such by the Federal Energy Regulatory Commission for interstate
transmission pipelines, individual States for intrastate transmission
pipelines, and the Hinshaw exemption under the Natural Gas Act for
Hinshaw transmission pipelines.  We propose to use this existing
mechanism to clearly demarcate transmission pipelines from distribution
and gathering pipelines.  Finally, we believe that equipment located on
designated transmission pipelines that are subject to monitoring under
subpart W are easily identifiable by facility owners or operators.  

Tubing Systems.  Based on a question received in the early phases of
implementation, we are proposing to clarify that the exclusion for
piping equal to or less than one half inch diameter applies to the
nominal pipe size (NPS). 

Vertical Well.  With the change from field level reporting to sub-basin
category, EPA is proposing to add a distinction for calculating
emissions from horizontal wells and vertical wells.  EPA proposes that a
vertical well means a well bore that is primarily vertical but has some
unintentional deviation or one or more intentional deviations to enter
one or more subsurface targets that are off-set horizontally from the
surface location, intercepting the targets either vertically or at an
angle.

Well Testing Venting and Flaring.  We are proposing to clarify that well
testing venting and flaring means venting and/or  flaring of natural gas
at the time the production rate of a well is determined (i.e., the well
testing) through a choke (an orifice restriction).  If well testing is
conducted immediately after well completion or workover we are proposing
to clarify that it is considered part of the well completion or
workover.

III.  Statutory and Executive Order Review

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

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

B.  Paperwork Reduction Act

This action proposes to simplify the existing reporting methodologies in
subpart W and clarify monitoring methodologies and data reporting
requirements.  In many cases, the proposed amendments to the reporting
requirements could potentially reduce the reporting burden by making the
reporting requirements conform more closely to current industry
practices.  In addition, while the proposed modification to one of the
monitoring methodologies is not expected to increase compliance cost, it
would require the reporting of information not contained in the
information collection requirements to 40 CFR 98 subpart W.  Therefore,
the proposed amendments to the information collection requirements have
been submitted for approval to the Office of Management and Budget (OMB)
under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The
Information Collection Request (ICR) document has been assigned EPA ICR
number 2376.03.    

The proposed amendments to subpart I would carry out the Agency’s
intent to require reporting of emissions of all fluorocarbons used as
heat transfer fluids in the electronics manufacturing industry.  This
was the intent of the subpart I reporting requirements for HTFs
finalized in December 2010 (75 FR 74774), and this intent was reflected
in the Information Collection Request (ICR) prepared during that
rulemaking.  Thus, the proposed amendments will not increase EPA or
industry burden beyond that estimated in the ICR.

The Office of Management and Budget (OMB) has previously approved the
information collection requirements contained in the existing
regulations, 40 CFR 98 subpart W (75 FR 74458), and 40 CFR part 98
subpart I (75 FR 74774),  under the provisions of the Paperwork
Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB control
number 2060-0651 and 2060-0650 respectively.  The OMB control numbers
for EPA's regulations in 40 CFR are listed in 40 CFR part 9.  

C.  Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA) generally requires an agency to
prepare a regulatory flexibility analysis of any rule subject to notice
and comment rulemaking requirements under the Administrative Procedure
Act or any other statute unless the agency certifies that the rule will
not have a significant economic impact on a substantial number of small
entities.  Small entities include small businesses, small organizations,
and small governmental jurisdictions.

For purposes of assessing the impacts of this proposed rule on small
entities, small entity is defined as: (1) a small business as defined by
the Small Business Administration’s (SBA)regulations at 13 CFR
121.201; (2) a small governmental jurisdiction that is a government of a
city, county, town, school district or special district with a
population of less than 50,000; and (3) a small organization that is any
not-for-profit enterprise which is independently owned and operated and
is not dominant in its field. 

After considering the economic impacts of today’s proposed rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities.  In
determining whether a rule has a significant economic impact on a
substantial number of small entities, the impact of concern is any
significant adverse economic impact on small entities, since the primary
purpose of the regulatory flexibility analyses is to identify and
address regulatory alternatives “which minimize any significant
economic impact of the rule on small entities” 5 USC 603 and 604. 
Thus, an agency may certify that a rule will not have a significant
economic impact on a substantial number of small entities if the rule
relieves regulatory burden, or otherwise has a positive economic effect
on all of the small entities subject to the rule.  	

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

D.  Unfunded Mandates Reform Act

The proposed rule amendments do not contain a Federal mandate that may
result in expenditures of $100 million or more for state, local, and
tribal governments, in the aggregate, or the private sector in any one
year.  Thus, the proposed rule amendments are not subject to the
requirements of section 202 and 205 of the UMRA.  This rule is also not
subject to the requirements of section 203 of UMRA because it contains
no regulatory requirements that might significantly or uniquely affect
small governments.  

This action is also not subject to the requirements of section 203 of
UMRA because it contains no regulatory requirements that might
significantly or uniquely affect small governments.  Further, the
proposed amendments will not impose any new requirements that are not
currently required for 40 CFR part 98, and the rule amendments would not
unfairly apply to small governments.  

E.  Executive Order 13132: Federalism

This action does not have federalism implications.  It will not have
substantial direct effects on the States, on the relationship between
the national government and the States, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132.  

Few, if any, State or local government facilities would be affected by
the provisions in this proposed rule.  This regulation also does not
limit the power of States or localities to collect GHG data and/or
regulate GHG emissions.  Thus, Executive Order 13132 does not apply to
this action.

In the spirit of Executive Order 13132, and consistent with EPA policy
to promote communications between EPA and State and local governments,
EPA specifically solicits comment on this proposed action from State and
local officials.

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

This action does not have tribal implications, as specified in Executive
Order 13175 (65 FR 67249, November 9, 2000).  During the finalization of
subpart W and subpart I, EPA undertook the necessary steps to determine
the impact of those rules on tribal entities and provided  supporting
documentation demonstrating the results of the Agency’s analyses.  The
proposed rule amendments in this action do not impose any significant
changes to the current reporting requirements contained in 40 CFR part
98 subpart W and 40 CFR part 98 subpart I.  And in several cases, the
proposed amendments to the reporting requirements would potentially
reduce the reporting burden.  Thus, Executive Order 13175 does not apply
to this action.

Although Executive Order 13175 does not apply to this action, EPA
consulted tribal officials during the development of the original
actions.  A summary of the concerns raised during the consultation and
EPA’s response to those concerns is provided in Sections VIII.E and
VIII.F of the preamble to the 2009 final rule and Section IV.F of the
preamble to the 2010 final rule for subpart W (75 FR 74485). EPA
specifically solicits additional comment on this proposed action from
tribal officials.

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

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

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

This action is not subject to Executive Order 13211 (66 FR 28355, May
22, 2001), because it is not a significant regulatory action under
Executive Order 12866.

I.  National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and Advancement Act of
1995 (NTTAA), Public Law No. 104-113, 12(d) (15 U.S.C. 272 note) directs
EPA to use voluntary consensus standards in its regulatory activities
unless to do so would be inconsistent with applicable law or otherwise
impractical.  Voluntary consensus standards are technical standards
(e.g., materials specifications, test methods, sampling procedures, and
business practices) that are developed or adopted by voluntary consensus
standards bodies.  NTTAA directs EPA to provide Congress, through OMB,
explanations when the Agency decides not to use available and applicable
voluntary consensus standards. 

This proposed rulemaking does not involve technical standards. 
Therefore, EPA is not considering the use of any voluntary consensus
standards.

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

Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
federal executive policy on environmental justice.  Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission by
identifying and addressing, as appropriate, disproportionately high and
adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.  

EPA has determined that this proposed rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it does not affect
the level of protection provided to human health or the environment
because it is a rule addressing information collection and reporting
procedures.

	



List of Subjects in 40 CFR Part 98

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

Dated:				

					

Lisa P. Jackson, 

Administrator.

For the reasons stated in the preamble, title 40, chapter I, of the
Code of Federal Regulations is proposed to be amended as follows:

PART 98—[AMENDED]

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

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

Subpart A-[Amended]

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

§98.1  Purpose and scope.

*	*	*	*	*

(c)  For facilities required to report under onshore petroleum and
natural gas production under subpart W of this part, the terms Owner and
Operator used in subpart A have the same definition as Onshore petroleum
and natural gas production owner or operator, as defined in §98.238 of
this part.

3.  Section 98.6 is amended by revising the definitions for
“Continuous bleed” and “Intermittent bleed pneumatic devices” to
read as follows:

§98.6  Definitions.

*	*	*	*	*

Continuous bleed means a continuous flow of pneumatic supply gas to the
process control device (e.g., level control, temperature control,
pressure control) where the supply gas pressure is modulated by the
process condition, and then flows to the valve controller where the
signal is compared with the process set-point to adjust gas pressure in
the valve actuator.

*	*	*	*	*

Intermittent bleed pneumatic devices mean automated flow control devices
powered by pressurized natural gas and used for automatically
maintaining a process condition such as liquid level, pressure,
delta-pressure, and temperature.  These are snap-acting or throttling
devices that discharge all or a portion of the full volume of the
actuator intermittently when control action is necessary, but do not
bleed continuously.

*	*	*	*	*

4.  Section 98.7 is amended by removing paragraph (q).

Subpart I—[Amended]

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

§98.90 Definition of the source category.

(a)	*	*	*

(5)  Any electronics manufacturing production process in which
fluorinated heat transfer fluids are used to cool process equipment, to
control temperature during device testing, to clean substrate surfaces
and other parts, and for soldering (e.g., vapor phase reflow).

6.  Section 98.92 is amended by revising paragraph (a) introductory text
and paragraph (a)(5) to read as follows:

§98.92 GHGs to report.

(a)  You must report emissions of fluorinated GHGs (as defined in
§98.6), N2O, and fluorinated heat transfer fluids (as defined in
§98.98).  The fluorinated GHGs and fluorinated heat transfer fluids
that are emitted from electronics manufacturing production processes
include, but are not limited to, those listed in Table I–2 to this
subpart.  You must individually report, as appropriate:

*	*	*	*	*

(5)  Emissions of fluorinated heat transfer fluids.

*	*	*	*	*

7.  Section 98.93 is amended by revising paragraph (h) introductory text
and the definition of “EHi” in Equation I-16 to read as follows.

§98.93 Calculating GHG Emissions.

*	*	*	*	*

(h)  If you use fluorinated heat transfer fluids, you must report the
annual emissions of fluorinated heat transfer fluids using the mass
balance approach described in Equation I-16 of this subpart.

*	*	*	*	*

EHi	=	Emissions of fluorinated heat transfer fluids i, (metric
tons/year).

*	*	*	*	*

8.  Section 98.94 is amended by revising paragraph (h) introductory text
to read as follows:

§98.94 Monitoring and QA/QC requirements.

*	*	*	*	*

(h)  You must adhere to the QA/QC procedures of this paragraph (h) when
calculating annual gas consumption for each fluorinated GHG and N2O used
at your facility and emissions from the use of fluorinated heat transfer
fluids.

*	*	*	*	*

9.  Section 98.96 is amended by revising paragraph (r) to read as
follows:

§98.96 Data Reporting requirements

*	*	*	*	*

(r)  For heat transfer fluid emissions, inputs to the heat transfer
fluid mass balance equation, Equation I–16 of this subpart, for each
fluorinated heat transfer fluid used. 

*	*	*	*	*

10.  Section 98.98 is amended by removing the definition of “Heat
transfer fluids” and adding the definition of “Fluorinated heat
transfer fluids” in alphabetical order to read as follows:

§98.98 Definitions.

*	*	*	*	*

Fluorinated heat transfer fluids means fluorinated GHGs used for
temperature control, device testing, cleaning substrate surfaces and
other parts, and soldering in certain types of electronics manufacturing
production processes.  For fluorinated heat transfer fluids under this
subpart I, the lower vapor pressure limit of 1 mm of Hg in absolute at
25 degrees C in the definition of Fluorinated greenhouse gas in 40 CFR
98.6 shall not apply.  Fluorinated heat transfer fluids used in the
electronics manufacturing sector include, but are not limited to,
perfluoropolyethers, perfluoroalkanes, perfluoroethers, tertiary
perfluoroamines, and perfluorocyclic ethers. 

*	*	*	*	*

11.  Table I–2 to Subpart I is amended by revising the title and the
second column heading to read as follows:

Table I-2 to Subpart I of Part 98—Examples of Fluorinated GHGs and
Fluorinated Heat Transfer Fluids Used by the Electronics Industry 

Product Type	Fluorinated GHGs and Fluorinated Heat Transfer Fluids Used
During Manufacture

Electronics	CF4, C2F6, C3F8, c-C4F8, c-C4F8O, C4F6, C5F8, CHF3, CH2F2,
NF3, SF6, and HTFs(CF3-(O-CF(CF3)-CF2)n-(O-CF2)m-O-CF3, CnF2n+2,
CnF2n+1(O)CmF2m+1, CnF2nO, (CnF2n+1)3N)



Subpart W—[Amended]

12.  Section 98.230 is amended by revising paragraphs (a)(2), (a)(3),
(a)(4), and (a)(8) to read as follows:

§98.230  Definition of the source category.

(a)  *	*	*

(2)  Onshore petroleum and natural gas production.  Onshore petroleum
and natural gas production means all equipment on a single well-pad or
associated with a single well-pad (including but not limited to
compressors, generators, dehydrators, storage vessels, and portable
non-self-propelled equipment which includes well drilling and completion
equipment, workover equipment, gravity separation equipment, auxiliary
non-transportation-related equipment, and leased, rented or contracted
equipment) used in the production, extraction, recovery, lifting,
stabilization, separation or treating of petroleum and/or natural gas
(including condensate).  This equipment also includes associated storage
or measurement vessels and all enhanced oil recovery (EOR) operations
using CO2 or natural gas injection, and all petroleum and natural gas
production equipment located on islands, artificial islands, or
structures connected by a causeway to land, an island, or an artificial
island.  

(3)  Onshore natural gas processing.  Natural gas processing means the
separation of natural gas liquids (NGLs) or non-methane gases from
produced natural gas, or the separation of NGLs into one or more
component mixtures.  Separation includes one or more of the following:
forced extraction of natural gas liquids, sulfur and carbon dioxide
removal, fractionation of NGLs, or the capture of CO2 separated from
natural gas streams.  This segment also includes all residue gas
compression equipment owned or operated by the natural gas processing
plant.  This industry segment includes processing plants that
fractionate gas liquids, and processing plants that do not fractionate
gas liquids but have an annual average throughput of 25 MMscf per day or
greater. 

(4)  Onshore natural gas transmission compression.  Onshore natural gas
transmission compression means any stationary combination of compressors
that move natural gas from production fields, natural gas processing
plants, or other transmission compressors through transmission pipelines
to natural gas distribution pipelines, LNG storage facilities, or into
underground storage.  In addition, a transmission compressor station
includes equipment for liquids separation, and tanks for the storage of
water and hydrocarbon liquids.  Residue (sales) gas compression that is
part of onshore natural gas processing plants are included in the
onshore natural gas processing segment and are excluded from this
segment.

*	*	*	*	*

(8)  Natural gas distribution.  Natural gas distribution means the
distribution pipelines and metering and regulating equipment at
metering-regulating stations that are operated by a Local Distribution
Company (LDC) within a single state that is regulated as a separate
operating company by a public utility commission or that is operated as
an independent municipally-owned distribution system.  This segment also
excludes customer meters and regulators, infrastructure, and pipelines
(both interstate and intrastate) delivering natural gas directly to
major industrial users and farm taps upstream of the local distribution
company inlet.

*	*	*	*	*

13.  Section 98.232 is amended by: 

a.  Revising paragraph (c) introductory text and paragraph (c)(22).

b.  Revising paragraph (e) introductory text.

c.  Revising paragraph (f) introductory text. 

d.  Revising paragraph (g) introductory text.

e.  Revising paragraph (h) introductory text.

f.  Revising paragraph (i) introductory text and paragraph (i)(1).

g.  Redesignating paragraphs (i)(2) through (i)(6) as paragraphs (i)(3)
through (i)(7), respectively.

h.  Revising newly designated paragraphs (i)(3) and (i)(4).

i.  Adding new paragraph (i)(2).

j.  Removing and reserving paragraph (j).

k.  Revising paragraph (k).

The revisions read as follows: 

§98.232  GHGs to report.

*	*	*	*	*

(c)  For an onshore petroleum and natural gas production facility,
report CO2, CH4, and N2O emissions from only the following source types
on a single well-pad or associated with a single well-pad:

*	*	*	*	*

(22)  You must use the methods in §98.233(z) and report under this
subpart the emissions of CO2, CH4, and N2O from stationary or portable
fuel combustion equipment that cannot move on roadways under its own
power and drive train, and that is located at an onshore petroleum and
natural gas production facility as defined in §98.238.  Stationary or
portable equipment are the following equipment, which are integral to
the extraction, processing, or movement of oil or natural gas: well
drilling and completion equipment, workover equipment, natural gas
dehydrators, natural gas compressors, electrical generators, steam
boilers, and process heaters.

*	*	*	*	*

(e)  For onshore natural gas transmission compression, report CO2, CH4,
and N2O emissions from the following sources:

*	*	*	*	*

(f)  For underground natural gas storage, report CO2, CH4, and N2O
emissions from the following sources:

*	*	*	*	*

(g)  For LNG storage, report CO2, CH4, and N2O emissions from the
following sources:

*	*	*	*	*

(h)  LNG import and export equipment, report CO2, CH4, and N2O emissions
from the following sources: 

*	*	*	*	*

(i)  For natural gas distribution, report CO2, CH4, and N2O emissions
from the following sources: 

 (1)  Meters, regulators, and associated equipment at above grade
transmission-distribution transfer stations, including equipment leaks
from connectors, block valves, control valves, pressure relief valves,
orifice meters, regulators, and open ended lines.

(2)  Equipment leaks from vaults at below grade
transmission-distribution transfer stations.

(3)  Meters, regulators, and associated equipment at above grade
metering-regulating station.

(4)  Equipment leaks from vaults at below grade metering-regulating
stations.

*	*	*	*	*

(j)  [Reserved]  

(k)  Report under subpart C of this part (General Stationary Fuel
Combustion Sources) the emissions of CO2, CH4, and N2O from each
stationary fuel combustion unit by following the requirements of subpart
C except for facilities under onshore petroleum and natural gas
production and natural gas distribution.  Onshore petroleum and natural
gas production facilities must report stationary and portable combustion
emissions as specified in paragraph (c) of this section.  Natural gas
distribution facilities must report stationary combustion emissions as
specified in paragraph (i) of this section.   

14.  Section 98.233 is amended by: 

In paragraph (a), revising Equation W-1 and the definitions of
“Count” and “GHGi” in Equation W-1; and adding the definition of
“T” in Equation W-1.

Adding paragraph (a)(3). 

In paragraph (c), revising Equation W-2 and the definition of
“GHGi”; and adding the definition of “T” in Equation W-2.

Revising paragraphs (d) introductory text and (d)(1). 

oving the definition of “α” in Equation W-4.

Revising paragraph (e)(1)(vii). 

Revising the definition of “1000” in Equation W-5 of paragraph
(e)(2). 

Revising paragraph (e)(6).

Revising paragraphs (f) introductory text, (f)(1) introductory text, and
the definitions of Equation W-7 in paragraph (f)(1).

Revising paragraphs (f)(1)(i)(A) through (f)(1)(i)(C). 

In paragraph (f)(2), revising Equation W-8 and the definitions of
Equation W-8.

Removing paragraphs (f)(2)(i) and (f)(2)(ii). 

In paragraph (f)(3), revising Equation W-9 and the definitions of
Equation W-9.

Removing paragraphs (f)(3)(i) and (f)(3)(ii). 

In paragraph (g), revising Equation W-10 and the definitions of Equation
W-10.

Revising paragraphs (g)(1) introductory text and (g)(1)(i) introductory
text. 

Removing paragraphs (g)(1)(i)(A) through (g)(1)(i)(D).

In paragraph (g)(1)(ii), revising the paragraph (g)(1)(ii) introductory
text; redesignating Equation W-11 as Equation W-11A and redesignating
Equation W-12 as Equation W-11B; and adding Equation W-11C.

Redesignating paragraphs (g)(1)(ii)(A) through (g)(1)(ii)(B) as
paragraphs (g)(1)(iii) through (g)(1)(v) and revising new paragraphs
(g)(1)(iii) through (g)(1)(v).

Removing paragraph (g)(1)(ii)(D). 

Revising paragraph (g)(3) introductory text and paragraph (g)(5)
introductory text.

In paragraph (h), revising the paragraph (h) introductory text and the
revising the definitions of “Nwo”, “f”, “Vp” and “Tp” in
Equation W-13.

Revising paragraph (i) introductory text and paragraphs (i)(1) and
(i)(2).

In paragraph (i)(3), revising the paragraph (i)(3) introductory text;
redesignating Equation W-14 as Equation W-14A; revising the definition
of “N” in newly redesignated Equation W-14A; and adding Equation
W-14B. 

Revising paragraph (i)(5).

Revising paragraph (j)(1)(vii)(B), (j)(1)(vii)(C), and (j)(3)(i).

Revising paragraphs (k)(1) and (k)(2)(i).

Revising paragraph (m)(1).

Revising paragraph (n)(2)(ii) and (n)(2)(iii), and in paragraph (n)(4),
revising equation W-21 and the definition for “Yj”.

Redesignating paragraph (n)(9) as paragraph (n)(10) and adding new
paragraphs (n)(9) and (n)(11). 

In paragraph (o)(6), revising the definition of “MTm” in Equation
W-24.

In paragraph (p)(7)(i), revising the definition of “MTm” in Equation
W-28.

In paragraph (q), revising equation W-30 and the definitions for
“x”, “EF”, “GHGi”, “Tp”, and revising paragraph (q)(8).

In paragraph (r), revising the definitions of “Counts”, “EFs”,
and “GHGi” in Equation W-31.  

Revising paragraphs (r)(2)(i)(A), (r)(6)(i), (r)(6)(ii) introductory
text, Equation W-32, and the definitions of Equation W-32. 

Revising paragraphs (t) introductory text, (t)(1) introductory text, and
(t)(2) introductory text. 

Revising paragraph (u) introductory text and paragraph (u)(2).

In paragraph (v), revising the paragraph (v) introductory text and the
definitions of “Masss,i”, “Es,i”, and “(i” in Equation W-36.


Revising paragraphs (z) introductory text, (z)(1) introductory text,
(z)(2) introductory text, (z)(2)(i), and (z)(2)(ii).

Adding paragraphs (z)(1)(i) and (z)(1)(ii). 

The revisions read as follows: 

§98.233 Calculating GHG emissions.

(a) *	*	*

 	(Eq. W-1)

*	*	*	*	*

Count	= 	Total number of continuous high bleed, continuous low bleed, or
intermittent bleed natural gas pneumatic devices of each type as
determined in paragraph (a)(1) and (a)(2) of this section. 

*	*	*	*	*

GHGi 	= 	For onshore petroleum and natural gas production facilities,
onshore natural gas transmission compression, and underground natural
gas storage, concentration of GHGi, CH4, or CO2, in natural gas as
defined in paragraph (u)(2)(i) of this section.

*	*	*	*	*

T	=	Total number of hours in the operating year the devices were
operational.

*	*	*	*	*

(3)  For all industry segments, determine the type of pneumatic device
using engineering estimates based on best available information.

*	*	*	*	*

(c) *	*	*

 	(Eq. W-2)

*	*	*	*	*

GHGi 	= 	Concentration of GHGi, CH4, or CO2, in produced natural gas as
defined in paragraph (u)(2)(i) of this section.

*	*	*	*	*

T 	= 	Total number of hours in the operating year the pumps were
operational.

*	*	*	*	*

(d)  Acid gas removal (AGR) vents.  For AGR vent (including processes
such as amine, membrane, molecular sieve or other absorbents and
adsorbents), calculate emissions for CO2 only (not CH4) vented directly
to the atmosphere or through a flare, engine (e.g., permeate from a
membrane or de-adsorbed gas from a pressure swing adsorber used as fuel
supplement), or sulfur recovery plant using any of the calculation
methodologies described in paragraph (d) of this section, as applicable.

*	*	*	*	*

	(1)  Calculation Methodology 1.  If you operate and maintain a CEMS
that has both a CO2 concentration monitor and volumetric flow rate
monitor, you must calculate CO2 emissions under this subpart by
following the Tier 4 Calculation Methodology and all associated
calculation, quality assurance, reporting, and recordkeeping
requirements for Tier 4 in subpart C of this part (General Stationary
Fuel Combustion Sources).  If a CO2 concentration monitor and  
volumetric flow rate monitor are not available, you may elect to install
a CO2 concentration monitor and a volumetric flow rate monitor  that
comply with all of the requirements specified for the Tier 4 Calculation
Methodology in subpart C of this part (General Stationary Fuel
Combustion).  The calculation and reporting of CH4 and N2O emissions is
not required as part of the Tier 4 requirements for AGRs.

*	*	*	*	*

(3)  *	*	*

 	(Eq. W-4)

*	*	*	*	*

(e)  *	*	*

(1)  *	*	*

(vii)  Use of stripping gas.

*	*	*	*	*

(2)  

*	*	*	*	*

1000 	= 	Conversion of EFi in thousand standard cubic feet to cubic
feet.

*	*	*	*	*

(6)  For glycol dehydrators, both CH4 and CO2 mass emissions shall be
calculated from volumetric GHGi emissions using calculations in
paragraph (v) of this section.  For dehydrators that use desiccant, both
CH4 and CO2 volumetric and mass emissions shall be calculated from
volumetric natural gas emissions using calculations in paragraphs (u)
and (v) of this section.

*	*	*	*	*

(f)  Well venting for liquids unloadings.  Calculate CO2 and CH4
emissions from  well venting for liquids unloading using one of the
calculation methodologies described in paragraphs (f)(1), (f)(2), or
(f)(3) of this section.

(1)  Calculation Methodology 1.  For one well of each unique well tubing
diameter grouping and pressure grouping in each sub-basin category (see
§98.238 for the definitions of tubing diameter grouping, pressure
grouping, and sub-basin category), where gas wells are vented to the
atmosphere to expel liquids accumulated in the tubing, a recording flow
meter shall be installed on the vent line used to vent gas from the well
(e.g., on the vent line off the wellhead separator or atmospheric
storage tank) according to methods set forth in §98.234(b).  Calculate
emissions from well venting for liquids unloading using Equation W-7 of
this section.

*	*	*	*	*

Ea,n	=	Annual natural gas emissions for wells of the same tubing
diameter grouping and pressure grouping at actual conditions in cubic
feet. 

Th,t	=	Cumulative amount of time in hours of venting from all wells of
the same tubing diameter grouping p and pressure grouping q during the
year.

FRh,t 	= 	Average flow rate in cubic feet per hour of a measured well
venting for the duration of the liquids unloading, under actual
conditions as determined in paragraph (f)(1)(i) of this section.

h	=	Total number of different tubing diameter groupings.

p	=	Tubing diameter grouping 1 through h.

t	=	Total number of pressure groupings.

q	=	Pressure grouping 1 through t.

*	*	*	*	*

(i)  *	*	*

(A)  The average flow rate per hour of venting is calculated for each
unique tubing diameter grouping and pressure grouping in each sub-basin
category by dividing the recorded total flow by the recorded time (in
hours) for a single liquid unloading with venting to the atmosphere. 

(B)  This average flow rate per hour is applied to all wells in the same
pressure grouping that have the same tubing diameter grouping, for the
number of hours of venting these wells.

(C)  A new average flow rate is calculated every other calendar year for
each reporting sub-basin category starting the first calendar year of
data collection.  For a new producing sub-basin category, an average
flow rate is calculated beginning in the first year of production. 

(2)  *	*	*

 	(Eq. W-8)

Where:

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

W	=	Total number of wells with well venting for liquids unloading at the
facility.

0.37×10-3	=	{3.14 (pi)/4}/{14.7*144} (psia converted to pounds per
square feet).

CDP	=	Casing diameter for each well, p, in inches.

WDP	=	Well depth from the lowest packer to the bottom of the well, in
feet.

SPP	=	Shut-in pressure for each well, p, in pounds per square inch
atmosphere (psia).

VP	=	Number of vents per year per well, p.

SFRP 	=	Average sales flow rate of gas well, p, at standard conditions
in cubic feet per hour.  Use Equation W-33 to calculate the sales flow
rate at standard conditions.

HRQ,PW 	=	Hours that each well,p , was left open to the atmosphere
during unloading, q.  

1.0	=	Hours for average well to blowdown casing volume at shut-in
pressure.

ZQ,P	=	If HRQ,P is less than 1.0 then ZQ,P is equal to 0.  If HRQ,P is
greater than or equal to 1.0 then ZQ,P is equal to 1.

(3)  *	*	*

 	(Eq. W-9)

Where:

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

W	=	Total number of wells with well venting for liquids unloading at the
facility. 

0.37×10-3	=	{3.14 (pi)/4}/{14.7*144} (psia converted to pounds per
square feet).

TDP	=	Tubing diameter for each well, p,in inches.

WDP	=	Tubing depth to plunger bumper for each well, p,  in feet.

SPP	=	Sales line pressure for each well, p, in pounds per square inch
atmospheric (psia).

VP	=	Number of vents per year for each well, p.

SFRP 	= 	Average sales flow rate of each gas well, p, at standard
conditions in cubic feet per hour.  Use Equation W-33 to calculate the
sales flow rate at standard conditions.

HRQ,P 	=	Hours that each well, p,  was left open to the atmosphere
during each unloading, q. 

0.5	= 	Hours for average well to blowdown tubing volume at sales line
pressure.

ZQ,P	=	If HRQ,P is less than 0.5 then ZQ,P is equal to 0.  If HRQ,P is
greater than or equal to 0.5 then ZQ,P is equal to 1.

*	*	*	*	*

(g)  *	*	*

  (Eq. W-10)

Where:

Es,n	=	Annual volumetric total gas emissions in cubic feet at standard
conditions from gas well venting during completions or workovers
following hydraulic fracturing for each sub-basin and well type
combination. 

Tp 	= 	Cumulative amount of time in hours of each well (p) completion or
workover venting in a sub-basin and well type combination during the
reporting year.

FRM	=	Venting to 30-day production ratio from Equation W-12.

PRp	=	First 30-day average production flow rate in standard cubic feet
per hour of each well (p), under actual conditions, converted to
standard conditions, as required in paragraph (g)(1) of this section.

EnFp	=	Volume of CO2 or N2 injected gas in cubic feet at standard
conditions that was injected into the reservoir during an energized
fracture job for each well (p).  If the fracture process did not inject
gas into the reservoir, then EnF is 0.  If injected gas is CO2, then EnF
is 0.

SGp	=	Volume of natural gas in cubic feet at standard conditions that
was recovered into a sales pipeline for well p as per paragraph (g)(3)
of this section.  If no gas was recovered for sales, SG is 0.

W	= 	Total number of wells completed or worked over using hydraulic
fracturing in a sub-basin and well type combination.

(1)  The average flow rate for gas well venting to the atmosphere or to
a flare during well completions and workovers from hydraulic fracturing
shall be determined using measurement(s) from either of the calculation
methodologies described in this paragraph (g)(1) of this section.  The
number of measurements shall be determined as follows:  One measurement
for less than or equal to 25 completions/workovers; two measurements for
26 to 50 completions/workovers; three measurements for 51 to 100
completions/workovers; four measurements for 101 to 250
completions/workovers; and five measurements for greater than 250
completions/workovers.

(i)  Calculation Methodology 1.  For well completion(s) in each gas
producing sub-basin category and well type (horizontal or vertical)
combination and for one well workover(s) in each gas producing sub-basin
category and well type (horizontal or vertical) combination, a recording
flow meter (digital or analog) shall be installed on the vent line,
ahead of a flare if used, to measure the backflow venting according to
methods set forth in §98.234(b). 

(ii)  Calculation Methodology 2.  For one horizontal well completion and
one vertical well completion in each gas producing sub-basin category
and for one well horizontal workover and one vertical well workover in
each gas producing sub-basin category, record the well flowing pressure
upstream (and downstream in subsonic flow) of a well choke according to
methods set forth in §98.234(b) to calculate the intermittent well flow
rate of gas during venting to the atmosphere or a flare.  Calculate
emissions using Equation W-11A of this section for subsonic flow or
Equation W-11B of this section for sonic flow.  Use Equation W-11C of
this section to determine whether flow is sonic or subsonic.  If the
value of R in Equation W-11C is greater than or equal to 2, then flow is
sonic; otherwise, flow is subsonic:

 	(Eq. W-11A)

Where:

FR	=	Average flow rate in cubic feet per hour, under subsonic flow
conditions.

A	=	Cross sectional area of orifice (m2).

P1	=	Upstream pressure (psia).

Tu	=	Upstream temperature (degrees Kelvin).

P2	=	Downstream pressure (psia).

3430	=	Constant with units of m2/(sec2 * K).

1.27*105	=	Conversion from m3/second to ft3/hour.

 	(Eq. W-11B)

Where:

FR	=	Average flow rate in cubic feet per hour, under sonic flow
conditions.

A	=	Cross sectional area of orifice (m2).

Tu	=	Upstream temperature (degrees Kelvin).

187.08	=	Constant with units of m2/(sec2 * K).

1.27*105	=	Conversion from m3/second to ft3/hour.

 	(Eq. W-11C)

Where:

R	=	Pressure ratio

P1	=	Pressure upstream of the restriction orifice in pounds per square
inch absolute.

P2	=	Pressure downstream of the restriction orifice in pounds per square
inch absolute.

(iii)  The emissions to 30-day production ratio is calculated using
Equation W-12 of this section. 

 	(Eq. W-12)

Where:

FRM	=	Emissions to 30-day production ratio.

FRp	=	Measured flow rate from Calculation Methodology 1 or estimated
flow rate from Calculation Methodology 2 in standard cubic feet per hour
for well(s) p for each sub-basin and well type (horizontal or vertical)
combination.

PRp	=	First 30-day production rate in standard cubic feet per hour for
each well p  that was measured in the sub-basin and well type
combination.

W	=	Number of wells completed or worked over using hydraulic fracturing
in a sub-basin and well type formation.

(iv)  The flow rates for horizontal and vertical wells are applied to
all horizontal and vertical well completions in the gas producing
sub-basin and well type combination and to all horizontal and vertical
well workovers, respectively, in the gas producing sub-basin and well
type combination for the total number of hours of venting of each of
these wells. 

(v)  New flow rates for horizontal and vertical gas well completions and
horizontal and vertical gas well workovers in each sub-basin category
shall be calculated once every two years starting in the first calendar
year of data collection. 

(2)  The volume of CO2 or N2 injected into the well reservoir during
energized hydraulic fractures will be measured using an appropriate
meter as described in §98.234(b) or using receipts of gas purchases
that are used for the energized fracture job. 

(i)  Calculate gas volume at standard conditions using calculations in
paragraph (t) of this section.

(ii)  [Reserved]

(3)  The volume of recovered completion or workover gas sent to a sales
line will be measured using existing company records.  If data does not
exist on sales gas, then an appropriate meter as described in
§98.234(b) may be used.

*	*	*	*	*

(5)  Determine if the well completion or workover from hydraulic
fracturing recovered gas with purpose designed equipment that separates
saleable gas from the backflow, and sent this gas to a sales line (e.g.,
reduced emissions completions or workovers).

*	*	*	*	*

(h)  Gas well venting during completions and workovers without hydraulic
fracturing.  Calculate CH4, CO2 and N2O (when flared) emissions from
each gas well venting during well completions and workovers not
involving hydraulic fracturing using Equation W-13 of this section:

*	*	*	*	*

 

Nwo	=	Number of workovers per sub-basin not involving hydraulic
fracturing in the reporting year.

f	=	Total number of well completions without hydraulic fracturing in a
sub-basin category.

Vp	= 	Average daily gas production rate in cubic feet per hour for each
well completion without hydraulic fracturing, p.  This is the total
annual gas production volume divided by total number  of hours the wells
produced to the sales line.  For completed wells that have not
established a production rate, you may use the average flow rate from
the first 30 days of production. In the event that the well is completed
less than 30 days from the end of the calendar year, the first 30 days
of the production straddling the current and following calendar years
shall be used. 

Tp	= 	Time each well completion without hydraulic fracturing, p, was
venting in hours during the year.*	*	*	*	*

(i)  Blowdown vent stacks.  Calculate CO2 and CH4 blowdown vent stack
emissions from depressurizing equipment to reduce system pressure for
planned or emergency shutdowns or to take equipment out of service for
maintenance (excluding depressurizing to a flare, over-pressure relief,
operating pressure control venting and blowdown of non-GHG gases;
desiccant dehydrator blowdown venting before reloading is covered in
paragraph (e)(5) of this section) as follows. : 

(1)  Calculate the total physical volume (including pipelines,
compressor case or cylinders, manifolds, suction bottles, discharge
bottles, and vessels) between isolation valves determined by engineering
estimates based on best available data.

(2)  If the total physical volume between isolation valves is greater
than or equal to 50 cubic feet, retain logs of the number of blowdowns
for each unique physical volume type (including but not limited to
compressors, vessels, pipelines, headers, fractionators, and tanks). 
Physical volumes smaller than 50 standard cubic feet are exempt from
reporting under paragraph (i) of this section.

(3)  Calculate the total annual venting emissions for each equipment
type using either Equation W-14A or W-14B of this section.   

 	(Eq. W-14A)

Where:

*	*	*	*	*

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

*	*	*	*	*

 		(Eq. W-14B)

Where:

Es,n 	= 	Annual natural gas venting emissions at standard conditions
from blowdowns in cubic feet.

N	= 	Number of repetitive blowdowns for each unique volume in calendar
year.

Vv	=	Total volume of blowdown equipment chamber (including pipelines,
compressors and vessels) between isolation valves in cubic feet for each
blowdown “i.”

C	=	Purge factor that is 1 if the equipment is not purged or zero if the
equipment is purged using non-GHG gases.

Ts  	=	Temperature at standard conditions (oF).

Ta  	=	Temperature at actual conditions in the blowdown equipment
chamber (oF) for each blowdown “i”.

Ps  	=	Absolute pressure at standard conditions (psia).

Pa,s,p  =	Absolute pressure at actual conditions in the blowdown
equipment chamber (psia) at the start of the blowdown “p”.

Pa,e,p  =	Absolute pressure at actual conditions in the blowdown
equipment chamber (psia) at the end of the blowdown “p”; 0 if
blowdown volume is purged using non-GHG gases.

*	*	*	*	*

(5)  Calculate total annual venting emissions for all blowdown vent
stacks by adding all standard volumetric and mass emissions determined
using Equations W-14A or W-14B and paragraph (i)(4) of this section.

(j)  *	*	*

(1)  *	*	*

(vii)  *	*	*

(B)  If separator oil composition and Reid vapor pressure data are
available through your previous analysis, select the latest available
analysis that is representative of produced crude oil or condensate from
the sub-basin category. 

(C)  Analyze a representative sample of separator oil in each sub-basin
category for oil composition and Reid vapor pressure using an
appropriate standard method published by a consensus-based standards
organization. 

*	*	*	*	*

(3)  *	*	*

(i)  If well production oil and gas compositions are available through
your previous analysis, select the latest available analysis that is
representative of produced oil and gas from the sub-basin category and
assume all of the CH4 and CO2 in both oil and gas are emitted from the
tank.

*	*	*	*	*

(k)  *	*	*

(1)  Monitor the tank vapor vent stack annually for emissions using an
optical gas imaging instrument according to methods set forth in
§98.234(a)(1) or by directly measuring the tank vent using a flow
meter, calibrated bag, or high volume sampler according to methods in
§98.234(b) through (d) for a duration of 5 minutes.  Or you may
annually monitor leakage through compressor scrubber dump valve(s) into
the tank using an acoustic leak detection device according to methods
set forth in §98.234(a)(5).

(2)  *	*	*

(i)  Use a meter, such as a turbine meter, calibrated bag, or high flow
sampler to estimate tank vapor volumes according to methods set forth in
§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 §98.233(k)(1) of this section to detect continuous
leakage, this serves as the measurement.

(m)  *	*	*

(1)  Determine the GOR of the hydrocarbon production from each well
whose associated natural gas is vented or flared.  If GOR from each well
is not available, the GOR from a cluster of wells in the same sub-basin
category shall be used.

*	*	*	*	*

(n)  *	*	*

(2)  *	*	*

(ii)  For onshore natural gas processing, when the stream going to flare
is natural gas, use the GHG mole percent in feed natural gas for all
streams upstream of the de-methanizer or dew point control, and GHG mole
percent in facility specific residue gas to transmission pipeline
systems for all emissions sources downstream of the de-methanizer
overhead or dew point control for onshore natural gas processing
facilities.  For onshore natural gas processing plants that solely
fractionate a liquid stream, use the GHG mole percent in feed natural
gas liquid for all streams.

(iii)  For any applicable industry segment, when the stream going to the
flare is a hydrocarbon product stream, such as methane, ethane, propane,
butane, pentane-plus and mixed light hydrocarbons, then you may use a
representative composition from the source for the stream determined by
engineering calculation based on process knowledge and best available
data.

*	*	*	*	*

(n)  *	*	*

            (Eq. W-21)

*	*	*	*	*

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

*	*	*	*	*

(9)  If you operate and maintain a CEMS that has both a CO2
concentration monitor and volumetric flow rate monitor, you must
calculate CO2 emissions for the flare by following the Tier 4
Calculation Methodology and all associated calculation, quality
assurance, reporting, and recordkeeping requirements for Tier 4 in
subpart C of this part (General Stationary Fuel Combustion Sources).  If
a CEMS is used to calculate flare stack emissions, the requirements
specified in paragraphs (n)(1) through (n)(7) are not required.  If a
CO2 concentration monitor and volumetric flow rate monitor are not
available, you may elect to install a CO2 concentration monitor and a
volumetric flow rate monitor that comply with all of the requirements
specified for the Tier 4 Calculation Methodology in subpart C of this
part (General Stationary Fuel Combustion).   

(10)  The flare emissions determined under paragraph (n) of this section
must be corrected for flare emissions calculated and reported under
other paragraphs of this section to avoid double counting of these
emissions. 

(11)  If source types in §98.233 use Equations W-19 through W-21 of
this section, use estimate of emissions under actual conditions for the
parameter, Va, in these equations.

(o)  *	*	*

(6)  *	*	*

*	*	*	*	*

MTm	=	Flow Measurements from all centrifugal compressor vents in each
mode in (o)(1)(i) through (o)(1)(iii) of this section in standard cubic
feet per hour.

*	*	*	*	*

(p)  *	*	*

(7)  *	*	*

(i)  *	*	*

*	*	*	*	*

MTm	=	Meter readings from all reciprocating compressor vents in each and
mode, m, in standard cubic feet per hour.

*	*	*	*	*

(q)  *	*	*

*	*	*	*	*

 				(Eq. W-30)

*	*	*	*	*

x	=	Total number of each equipment leak source.

*	*	*	*	*

GHGi	=	For onshore natural gas processing facilities, concentration of
GHGi, CH4 or CO2, in the total hydrocarbon of the feed natural gas;
98.230(a)(4) and (a)(5),GHGi equals 0.974 for CH4 and 1.0 × 10-2 for
CO2; for facilities listed in §98.230(a)(6) and (a)(7), GHGi equals 1
for CH4 and 0 for CO2; and for facilities listed in §98.230(a)(8), GHGi
equals 1 for CH4 and 1.1×10-2 CO2.

Tp	=	The total time the component, p, was found leaking and operational,
in hours.  If one leak detection survey is conducted, assume the
component was leaking for the entire calendar year.  If multiple leak
detection surveys are conducted, assume that the component found to be
leaking has been leaking since the previous survey or the beginning of
the calendar year.  For the last leak detection survey in the calendar
year, assume that all leaking components continue to leak until the end
of the calendar year.

*	*	*	*	*

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

(r)  *	*	*

*	*	*	*	*

Counts	=	Total number of this type of emission source at the facility. 
For onshore petroleum and natural gas production, average component
counts are provided by major equipment piece in Tables W-1B and Table
W-1C of this subpart.  Use average component counts as appropriate for
operations in Eastern and Western U.S., according to Table W-1D of this
subpart.  Underground natural gas storage shall count the components
listed for population emission factors in Table W-4.  LNG Storage shall
count the number of vapor recovery compressors.  LNG import and export
shall count the number of vapor recovery compressors.  Natural gas
distribution shall count the respective component for each emission
factor as described in paragraph (r)(6) of this section.

EFs	=	Population emission factor for the specific source, as listed in
Table W-1A and Tables W-3 through Table W-7 of this subpart.  Use
appropriate population emission factor for operations in Eastern and
Western U.S., according to Table W-1D of this subpart.  EF for
meter/regulator runs at above grade metering-regulating stations is
determined in Equation W-32 of this section. 

GHGi	=	For onshore petroleum and natural gas production facilities,
concentration of GHGi, CH4 or CO2, in produced natural gas; for other
facilities listed in §98.230(a)(4) and (a)(5),GHGi equals 0.952 for CH4
and 1.0 × 10-2 for CO2; for facilities listed in §98.230(a)(6) and
(a)(7), GHGi equals 1 for CH4 and 0 for CO2; and for facilities listed
in §98.230(a)(8), GHGi equals 1 for CH4 and 1.1×10-2 CO2.

*	*	*	*	*

(2)  *	*	*

(i)  *	*	*

(A)  Count all major equipment listed in Table W-1B and Table W-1C of
this subpart.  For meters/piping, use one meters/piping per well-pad. 

*	*	*	*	*

(6)  *	*	*

(i)  Below grade metering-regulating stations (including below grade T-D
transfer stations); distribution mains; and distribution services, shall
use the appropriate default population emission factors listed in Table
W-7 of this subpart. 

(ii)  Emissions from all above grade metering-regulating stations
(including above grade TD transfer stations) shall be calculated by
applying the emission factor calculated in Equation W-32 and the total
count of meter/regulator runs at all above grade metering-regulating
stations (inclusive of TD transfer stations) to Equation W-31.  The
facility wide emission factor in Equation W-32 will be calculated by
using the total volumetric GHG emissions at standard conditions for all
equipment leak sources calculated in paragraph (q)(8) of this section
and the count of meter/regulator runs located at above grade
transmission-distribution transfer stations.

 	(Eq. W-32)

Where:

EFi	=	Facility emission factor for a meter/regulator run at above grade
metering-regulating for GHGi in cubic feet per meter/regulator run per
hour.

Es,i	=	Annual volumetric GHG i emissions, CO2 or CH4 at standard
condition from all equipment leak sources at all above grade TD transfer
stations, from paragraph (q) of this section.

Count	=	Total number of meter/regulator runs at all TD transfer
stations.

8760	=	Conversion to hourly emissions

*	*	*	*	*

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

(1)  Calculate natural gas volumetric emissions at standard conditions
using actual natural gas emission temperature and pressure, and Equation
W-33 of this section.

*	*	*	*	*

(2)  Calculate GHG volumetric emissions at standard conditions using
actual GHG emissions temperature and pressure, and Equation W-34 of this
section.

*	*	*	*	*

(u)  GHG volumetric emissions.  Calculate GHG volumetric emissions at
standard conditions as specified in paragraphs (u)(1) and (2) of this
section, with mole fraction of GHGs in the natural gas determined by
engineering estimate based on best available data unless otherwise
specified.

*	*	*	*	*

(2)  For Equation W-35 of this section, the mole fraction, Mi, shall be
the annual average mole fraction for each sub-basin category or
facility, as specified in paragraphs (u)(2)(i) through (vii) of this
section.

(i)  GHG mole fraction in produced natural gas for onshore petroleum and
natural gas production facilities.  If you have a continuous gas
composition analyzer for produced natural gas, you must use an annual
average of these values for determining the mole fraction.  If you do
not have a continuous gas composition analyzer, then you must use an
annual average gas composition based on available analyses in each of
the sub-basin categories.

(ii)  GHG mole fraction in feed natural gas for all emissions sources
upstream of the de-methanizer or dew point control and GHG mole fraction
in facility specific residue gas to transmission pipeline systems for
all emissions sources downstream of the de-methanizer overhead or dew
point control for onshore natural gas processing facilities.  For
onshore natural gas processing plants that solely fractionate a liquid
stream, use the GHG mole percent in feed natural gas liquid for all
streams.  If you have a continuous gas composition analyzer on feed
natural gas, you must use these values for determining the mole
fraction.  If you do not have a continuous gas composition analyzer,
then annual samples must be taken according to methods set forth in
§98.234(b).

(iii)  GHG mole fraction in transmission pipeline natural gas that
passes through the facility for onshore natural gas transmission
compression facilities.  You may use a default 95 percent methane and 1
percent carbon dioxide fraction for GHG mole fraction in natural gas. 

(iv)  GHG mole fraction in natural gas stored in underground natural gas
storage facilities.  You may use a default 95 percent methane and 1
percent carbon dioxide fraction for GHG mole fraction in natural gas.  

(v)  GHG mole fraction in natural gas stored in LNG storage facilities. 
You may use a default 95 percent methane and 1 percent carbon dioxide
fraction for GHG mole fraction in natural gas. 

(vi)  GHG mole fraction in natural gas stored in LNG import and export
facilities.  For export facilities that receive gas from transmission
pipelines, you may use a default 95 percent methane and 1 percent carbon
dioxide fraction for GHG mole fraction in natural gas. 

(vii)  GHG mole fraction in local distribution pipeline natural gas that
passes through the facility for natural gas distribution facilities. 
You may use a default 95 percent methane and 1 percent carbon dioxide
fraction for GHG mole fraction in natural gas.

(v)  GHG mass emissions.  Calculate GHG mass emissions in carbon dioxide
equivalent at standard conditions by converting the GHG volumetric
emissions at standard conditions into mass emissions using Equation W-36
of this section.

*	*	*	*	*

Masss,i	=	GHG i (either CH4 , CO2, or N2O) mass emissions at standard
conditions in metric tons CO2e.  

Es,i	=	GHG i (either CH4, CO2, or N2O) volumetric emissions at standard
conditions, in cubic feet.

	=	Density of GHG i. Use 0.0520 kg/ft3 for CO2 and N2O, and 0.0190
kg/ft3 for CH4 at 68°F and 14.7 psia or 0.0530 kg/ft3 for CO2 and N2O,
and 0.0193 kg/ft3 for CH4 at 60°F and 14.7 psia .

*	*	*	*	*

(z)  Onshore petroleum and natural gas production and natural gas
distribution combustion emissions.  Calculate CO2, CH4, and N2O
combustion-related emissions from stationary or portable equipment,
except as specified in paragraph (z)(3) of this section, as follows:

(1)  If a fuel combusted in the stationary or portable equipment is
listed in Table C–1 of subpart C of this part, or is a blend
containing one   or more fuels listed in Table C–1, calculate
emissions according to (z)(1)(i).  If the fuel is natural gas and is of
pipeline quality specification and has a minimum high heat value of 950
Btu per standard cubic foot, use the calculation methodology described
in (z)(1)(i) and you may use the emission factor provided for natural
gas as listed in Table C-1.  If the fuel is natural gas, and is not
pipeline quality or has a high heat value of less than 950 But per
standard cubic feet, calculate emissions according to (z)(2).  If the
fuel is field gas, process vent gas, or a blend containing field gas or
process vent gas, calculate emissions according to (z)(2).

(i)  For fuels listed in Table C-1 or a blend containing one more fuels
listed in Table C-1, calculate CO2, CH4, and N2O emissions according to
any Tier listed in subpart C of this part.  You must follow all
applicable calculation requirements for that tier listed in 98.33, any
monitoring or QA/QC requirements listed for that tier in 98.34, any
missing data procedures specified in 98.35, and any recordkeeping
requirements specified in 98.37. 

(ii)  Emissions from fuel combusted in stationary or portable equipment
at onshore natural gas and petroleum production facilities and at
natural gas distribution facilities will be reported according to the
requirements specified in 98.236(c)(19) and not according to the
reporting requirements specified in subpart C of this part. 

(2)  For fuel combustion units that combust field gas, process vent gas,
a blend containing field gas or process vent gas, or natural gas that is
not of pipeline quality or that has a high heat value of less than 950
Btu per standard cubic feet, calculate combustion emissions as follows:

(i)  You may use company records to determine the volume of fuel
combusted in the unit during the reporting year. 

(ii)  If you have a continuous gas composition analyzer on fuel to the
combustion unit, you must use these compositions for determining the
concentration of gas hydrocarbon constituent in the flow of gas to the
unit. If you do not have a continuous gas composition analyzer on gas to
the combustion unit, you must use the appropriate gas compositions for
each stream of hydrocarbons going to the combustion unit as specified in
paragraph (u)(2)(i) of this section.

15.  Section 98.234 is amended by: 

a.  Revising paragraphs (a)(1), (a)(2), and (a)(5). 

b.  Removing and reserving paragraph (a)(4).

c.  Revising paragraph (c) introductory text and paragraph (d)(3).  

§98.234  Monitoring and QA/QC requirements.

(a)  *	*	*

(1)  Optical gas imaging instrument.  Use an optical gas imaging
instrument for equipment leak detection in accordance with 40 CFR part
60, subpart A, §60.18 of the Alternative work practice for monitoring
equipment leaks, §60.18(i)(1)(i); §60.18(i)(2)(i) except that the
monitoring frequency shall be annual using the detection sensitivity
level of 60 grams per hour as stated in 40 CFR Part 60, Subpart A, Table
1: Detection Sensitivity Levels; §60.18(i)(2)(ii) and (iii) except the
gas chosen shall be methane, and §60.18(i)(2)(iv) and (v);
§60.18(i)(3); §60.18(i)(4)(i) and (v); including the requirements for
daily instrument checks and distances, and excluding requirements for
video records.  Any emissions detected by the optical gas imaging
instrument is a leak unless screened with Method 21 (40 CFR part 60,
appendix A-7) monitoring, in which case 10,000 ppm or greater is
designated a leak.  In addition, you must operate the optical gas
imaging instrument to image the source types required by this subpart in
accordance with the instrument manufacturer’s operating parameters. 
An optical gas imaging instrument must be used for all source types that
are inaccessible and cannot be monitored without elevating the
monitoring personnel more than 2 meters above a support surface.

(2)  Method 21.  Use the equipment leak detection methods in 40 CFR part
60, appendix A-7, Method 21.  If using Method 21 monitoring, if an
instrument reading of 10,000 ppm or greater is measured, a leak is
detected.  Inaccessible emissions sources, as defined in 40 CFR part 60,
are not exempt from this subpart.  Owners or operators must use
alternative leak detection devices as described in paragraph (a)(1) or
(a)(2) of this section to monitor inaccessible equipment leaks or vented
emissions.

*	*	*	*	*

(5)  Acoustic leak detection device.  Use the acoustic leak detection
device to detect through-valve leakage.  When using the acoustic leak
detection device to quantify the through-valve leakage, you must use the
instrument manufacturer’s calculation methods to quantify the
through-valve leak.  When using the acoustic leak detection device, if a
leak of 3.1 scf per hour or greater is calculated, a leak is detected. 
In addition, you must operate the acoustic leak detection device to
monitor the source valves required by this subpart in accordance with
the instrument manufacturer’s operating parameters.  Acoustic
stethoscope type devices designed to detect through valve leakage when
put in contact with the valve body and that provide an audible leak
signal but do not calculate a leak rate can be used to identify
non-leakers with subsequent measurement required to calculate the rate
if through-valve leakage is identified.  Leaks are reported if a leak
rate of 3.1 scf per hour or greater is measured.

*	*	*	*	*

 (c)  Use calibrated bags (also known as vent bags) only where the
emissions are at near-atmospheric pressures and below the maximum
temperature specified by the vent bag manufacturer such that the bag is
safe to handle.  The bag must be of sufficient size that the entire
emissions volume can be encompassed for measurement.

*	*	*	*	*

(d)  *	*	*

(3)  Estimate natural gas volumetric emissions at standard conditions
using calculations in §98.233(t).  Estimate CH4 and CO2 volumetric and
mass emissions from volumetric natural gas emissions using the
calculations in §98.233(u) and (v).

16.  Section 98.236 is amended by: 

Revising paragraphs (a) introductory text and (a)(8). 

Revising paragraph (b).

Revising paragraphs (c) introductory text, (c)(1)(iv), (c)(2)(ii), and
(c)(3)(ii) through (c)(3)(v); and adding paragraphs (c)(3)(vi) and
(vii).

Revising paragraphs (c)(4)(i)(H) and (C)(4)(i)(J); and adding paragraphs
(c)(4)(i)(K) and (c)(4)(i)(L).

Revising paragraphs (c)(4)(ii)(B) and (c)(4)(ii)(C); and adding
paragraph (c)(4)(ii)(D).

Revising paragraph (c)(4)(iii)(B).

Revising paragraphs (c)(5) introductory text, (c)(5)(iii), and
(c)(5)(vi); and adding paragraph (c)(5)(vii).

Revising paragraphs (c)(6) introductory text, (c)(6)(i) introductory
text, (c)(6)(i)(B), (c)(6)(i)(D), (c)(6)(i)(G), and (c)(6)(i)(H); and
adding paragraph (c)(6)(ii)(I).

Revising paragraphs (c)(6)(ii)(B) and (c)(6)(ii)(D); and adding
paragraph (c)(6)(ii)(E).

Revising paragraphs (c)(7)(i) and (c)(7)(ii); and adding paragraphs
(c)(7)(iii).

Revising paragraphs (c)(8)(i) introductory text and (c)(8)(i)(J); and
adding paragraphs (c)(8)(i)(K) through (c)(8)(i)(M).

Revising paragraphs (c)(8)(ii) introductory text, (c)(8)(ii)(D), and
(c)(8)(ii)(G); and adding paragraphs (c)(8)(ii)(H) and (c)(8)(ii)(I). 

Revising paragraphs (c)(8)(iii) introductory text and (c)(8)(iii)(F);
and adding paragraphs (c)(8)(iii)(G) and (c)(8)(iii)(H). 

Adding paragraph (c)(8)(iv)(B).

Revising paragraphs (c)(9)(i) and (c)(9)(ii); and adding paragraph
(c)(9)(iii). 

Revising paragraphs (c)(10) introductory text and (c)(10)(iv); and
adding paragraph (c)(10)(v). 

Revising paragraph (c)(11) introductory text and (c)(11)(iii); and
adding paragraph (c)(11)(iv). 

Revising paragraph (c)(12)(vi) and adding paragraphs (c)(12)(vii)
through (c)(12)(xi).

Revising paragraphs (c)(15)(i)(B) and (c)(15)(i)(C). 

Revising paragraphs (c)(15)(ii)(A) through (c)(15)(ii)(C). 

Revising paragraphs (c)(16)(i) through (c)(16)(iv), (c)(16)(vi), and
(c)(16)(xv).

Removing and reserving paragraph (c)(16)(v).

Adding paragraphs (c)(16)(xvi) through (c)(16)(xx).

Revising paragraph (c)(17)(v) and adding paragraph (c)(17)(vi).

Revising paragraph (c)(18) introductory text and paragraph (c)(18)(iii).


Revising paragraph (c)(19)(iii) and (c)(19)(vi).

Adding paragraph (e). 

The revisions read as follows:

§98.236   Data Reporting Requirements .

*	*	*	*	*

(a)  Report annual emissions separately for each of the industry
segments listed in paragraphs (a)(1) through (8) of this section. 

*	*	*	*	*

(8)  Natural gas distribution.

(b)  For offshore petroleum and natural gas production, report emissions
of CH4, CO2, and N2O as applicable to the source type (in metric tons
CO2e per year at standard conditions) individually for all the emissions
source types listed in the most recent BOEMRE study.  

(c)  Report the information listed in this paragraph for each applicable
source type.  If a facility operates under more than one industry
segment, each piece of equipment should be reported under its respective
majority use segment.  When a source type listed under this paragraph
routes gas to flare, separately report the emissions that were vented
directly to the atmosphere without flaring, and the emissions that
resulted from flaring the gas.  Both the vented and flared emissions
will be reported under the respective source type and not under the
flare source type.

(1)  *	*	*

(iv)  Report annual CO2 and CH4 emissions at the facility level,
expressed in metric tons CO2e for each gas, for each of the following
pieces of equipment:  high bleed pneumatic devices; intermittent bleed
pneumatic devices; low bleed pneumatic devices.

(2)  *	*	*

(ii)  Report annual CO2 and CH4 emissions at the facility level,
expressed in metric tons CO2e for each gas, for all natural gas driven
pneumatic pumps combined.

(3)  *	*	*

(ii)  For Calculation Methodology 1 and Calculation Methodology 2 of
§98.233(d), annual average fraction of CO2 content in the vent from the
acid gas removal unit (refer to §98.233(d)(6)).

(iii)  For Calculation Methodology 3 of §98.233(d), annual average
volume fraction of CO2 content of natural gas into and out of the acid
gas removal unit (refer to §98.233(d)(7) and (d)(8)).

(iv)	 Report the annual quantity of CO2, expressed in metric tons CO2e,
that was recovered from the AGR unit and transferred outside the
facility.

(v)  Report annual CO2 emissions for the AGR unit, expressed in metric
tons CO2e.

(vi)  A unique name or ID number for the AGR unit. 

(vii)  An indication of which calculation methodology was used for the
AGR.

(4)  *	*	*

(i)  *	*	*

(H)  Concentration of CH4 and CO2 in wet natural gas. 

*	*	*	*	*

(J)  For each glycol dehydrator, report annual CO2 and CH4 emissions
that resulted from venting gas directly to the atmosphere, expressed in
metric tons CO2e for each gas.

(K)  For each glycol dehydrator, report annual CO2, CH4, and N2O
emissions that resulted from flaring process gas from the dehydrator,
expressed in metric tons CO2e for each gas.

(L)  A unique name or ID number for the glycol dehydrator.

(ii)  *	*	*

(B)  Which vent gas controls are used (refer to §98.233(e)(3) and
(e)(4)).

(C)  Report annual CO2 and CH4 emissions at the facility level that
resulted from venting gas directly to the atmosphere, expressed in
metric tons CO2e for each gas, combined for all glycol dehydrators with
a throughput of less than 0.4 MMscfd.

(D)  Report annual CO2, CH4, and N2O emissions at the facility level
that resulted from the flaring of process gas, expressed in metric tons
CO2e for each gas, combined for all glycol dehydrators with a throughput
of less than 0.4 MMscfd.

(iii)  *	*	*

(B)  Report annual CO2 and CH4 emissions at the facility level,
expressed in metric tons CO2e for each gas, for all absorbent desiccant
dehydrators combined.

(5)  For well venting for liquids unloading (refer to Equations W-7, W-8
and W-9 of §98.233), report the following by each well tubing diameter
grouping and pressure grouping within each sub-basin category:

*	*	*	*	*

(iii)  Cumulative number of unloadings vented to the atmosphere.

*	*	*	*	*

(vi)  Report annual CO2 and CH4 emissions, expressed in metric tons CO2e
for each gas, for each tubing diameter and pressure grouping within each
sub-basin category.

(vii)  When using Calculation Methodology 1, casing diameter, depth and
pressure of each well selected to represent emissions in that tubing
size and pressure combination (refer to Equation W-7 of §98.233).

(6)  For well completions and workovers, report the following for each
sub-basin category: 

(i)  For gas well completions and workovers with hydraulic fracturing by
sub-basin and well type (horizontal or vertical) combination (refer to
Equation W-10 of §98.233):

*	*	*	*	* 

(B)  Average flow rate of the measured well completion venting in cubic
feet per hour (refer to Equation W-12 of §98.233).

*	*	*	*	* 

(D)  Average flow rate of the measured well workover venting in cubic
feet per hour (refer to Equation W-12 of §98.233).

*	*	*	*	* 

(G)  Report number of completions and number of workovers employing
reduced emissions completions and engineering estimate based on best
available data of the amount of gas recovered to sales.

(H)  Annual CO2 and CH4 emissions that resulted from venting gas
directly to the atmosphere, expressed in metric tons CO2e for each gas.

(I)  Annual CO2, CH4, and N2O emissions that resulted from flares,
expressed in metric tons CO2e for each gas.

*	*	*	*	* 

(B)  Total count of workovers in calendar year that flare gas or vent
gas to the atmosphere.

*	*	*	*	* 

(D)  Annual CO2 and CH4 emissions that resulted from venting gas
directly to the atmosphere, expressed in metric tons CO2e for each gas.

(E)  Annual CO2, CH4, and N2O emissions that resulted from flares,
expressed in metric tons CO2e for each gas.

(7)  *	*	*

(i)  Total number of blowdowns per unique volume type in calendar year. 

(ii)  Annual CO2 and CH4 emissions, expressed in metric tons CO2e for
each gas, for each unique volume type, at each blowdown stack.

(iii)  A unique name or ID number for the blowdown vent stack.

(8)  *	*	*

(i)  For wellhead gas-liquid separator with oil throughput greater than
or equal to 10 barrels per day, using Calculation Methodology 1 and 2 of
§98.233(j), report the following by sub-basin category, unless
otherwise specified:

*	*	*	*	*

(J)  Annual CO2 and CH4 emissions that resulted from venting gas to the
atmosphere, expressed in metric tons CO2e for each gas, for each
wellhead gas-liquid separator or storage tank using Calculation
Methodology 1 or 2 of §98.233(j).

(K)  Annual CO2 and CH4 gas quantities that were recovered, expressed in
metric tons CO2e for each gas, for each wellhead gas-liquid separator or
storage tank using Calculation Methodology 1 or 2 of §98.233(j).

(L)  Annual CO2, CH4, and N2O emissions that resulted from flaring gas,
expressed in metric tons CO2e for each gas, for each wellhead gas-liquid
separator or storage tank using  Calculation Methodology 1 or 2 of
§98.233(j).

(M)  A unique name or ID number for each wellhead gas liquid separator
or storage tank.

(ii)  For wells with oil production greater than or equal to 10 barrels
per day, using Calculation Methodology 3 and 4 of §98.233(j), report
the following by sub-basin category: 

*	*	*	*	* 

(D)  Sales oil API gravity range for wells in (c)(8)(ii)(B) and
(c)(8)(ii)(C) of this section, in degrees. 

*	*	*	*	* 

(G)  Annual CO2 and CH4 emissions that resulted from venting gas to the
atmosphere, expressed in metric tons CO2e for each gas, at the sub-basin
level for Calculation Methodology 3 or 4 of §98.233(j).

(H)  Annual CO2 and CH4 gas quantities that were recovered, expressed in
metric tons CO2e for each gas, at the sub-basin level for Calculation
Methodology 3 or 4 of §98.233(j).

(I)  Annual CO2, CH4, and N2O emissions that resulted from flaring gas,
expressed in metric tons CO2e for each gas, at the sub-basin level for
Calculation Methodology 3 and 4 of §98.233(j).

(iii)  For wellhead gas-liquid separators and wells with throughput less
than 10 barrels per day, using Calculation Methodology 5 of §98.233(j)
Equation W-15 of §98.233, report the following:

*	*	*	*	*

(F)  Annual CO2 and CH4 emissions that resulted from venting gas to the
atmosphere, expressed in metric tons CO2e for each gas, at the sub-basin
level for Calculation Methodology 5 of §98.233(j).

(G)  Annual CO2 and CH4 gas quantities that were recovered, expressed in
metric tons CO2e for each gas, at the sub-basin level for Calculation
Methodology 5 of §98.233(j).

(H)  Annual CO2, CH4, and N2O emissions that resulted from flaring gas,
expressed in metric tons CO2e for each gas, at the sub-basin level for
Calculation Methodology 5 of §98.233(j).

(iv)  *	*	*

(B)  Annual CO2 and CH4 emissions that resulted from venting gas to the
atmosphere, expressed in metric tons CO2e for each gas, at the sub-basin
level for improperly functioning dump valves.

(9)  *	*	*

(i)  For each transmission storage tank, report annual CO2 and CH4
emissions that resulted from venting gas directly to the atmosphere,
expressed in metric tons CO2e for each gas.

(ii)  For each transmission storage tank, report annual CO2, CH4, and
N2O emissions that resulted from flaring process gas from the
transmission storage tank, expressed in metric tons CO2e for each gas.

(iii)  A unique name or ID number for the transmission storage tank. 

(10)  For well testing venting and flaring (refer to Equation W-17 of
§98.233), report the following:

*	*	*	*	*

(iv)  Report annual CO2 and CH4 emissions at the facility level,
expressed in metric tons CO2e for each gas, emissions from well testing
venting.

(v)  Report annual CO2, CH4, and N2O emissions at the facility level,
expressed in metric tons CO2e for each gas, emissions from well testing
flaring.

(11)  For associated natural gas venting and flaring (refer to Equation
W-18 of §98.233), report the following for each basin:

*	*	*	*	*

(iii)  Report annual CO2 and CH4 emissions at the facility level,
expressed in metric tons CO2e for each gas, emissions from associated
natural gas venting.

(iv)  Report annual CO2, CH4, and N2O emissions at the facility level,
expressed in metric tons CO2e for each gas, emissions from associated
natural gas flaring.

(12)  *	*	*

(vi)  Report uncombusted CH4 emissions, in metric tons CO2e (refer to
Equation W-19 of §98.233). 

(vii)  Report uncombusted CO2 emissions, in metric tons CO2e (refer to
Equation W-20 of §98.233). 

(viii)  Report combusted CO2 emissions, in metric tons CO2e (refer to
Equation W-21 of §98.233).  

(ix)  Report N2O emissions, in metric tons CO2e.

(x)  A unique name or ID number for the flare stack.

(xi)  In the case that a CEMS is used to measure CO2 emissions for the
flare stack, indicate that a CEMS was used in the annual report and
report the combusted CO2 and uncombusted CO2 as a combined number.

(15)  *	*	*

(i)  *	*	*

(B)  For onshore natural gas processing, range of concentrations of CH4
and CO2 (refer to Equation W-30 of §98.233).

(C)	Annual CO2 and CH4 emissions, in metric tons CO2e for each gas
(refer to Equation W-30 of §98.233), by equipment type.

(ii)  *	*	*

(A)  For source categories §98.230(a)(4), (a)(5), (a)(6), (a)(7), and
(a)(8), total count for each type of leak source in Tables W-2, W-3,
W-4, W-5, and W-6 of this subpart for which there is a population
emission factor, listed by major heading and component type.

(B)  For onshore production (refer to §98.230 paragraph (a)(2)), total
count for each type of major equipment in Table W-1B and Table W-1C of
this subpart, by sub-basin category.

(C)  Annual CO2 and CH4 emissions, in metric tons CO2e for each gas
(refer to Equation W-31 of §98.233), by equipment type.

(16)  *	*	*

(i)  Number of above grade T-D transfer stations.

(ii)  Number of below grade T-D transfer stations.

(iii)  Number of above grade metering-regulating stations (this count
will include above grade T-D transfer stations).

(iv)  Number of below grade metering-regulating stations (this count
will include below grade T-D transfer stations).

(v)  [Reserved]

(vi)  Above grade metering-regulating station leak factor (refer to
Equation W-32 of §98.233).

*	*	*	*	*

(xv)  Annual CO2 and CH4 emissions, in metric tons CO2e for each gas,
from all above grade T-D transfer stations combined. 

(xvi)  Annual CO2 and CH4 emissions, in metric tons CO2e for each gas,
from all below grade T-D transfer stations combined. 

(xvii)  Annual CO2 and CH4 emissions, in metric tons CO2e for each gas,
from all above grade metering-regulating stations (including T-D
transfer stations) combined.

(xviii)  Annual CO2 and CH4 emissions, in metric tons CO2e for each gas,
from all below grade metering-regulating stations (including T-D
transfer stations) combined.

(xix)  Annual CO2 and CH4 emissions, in metric tons CO2e for each gas,
from all distribution mains combined.

(xx)  Annual CO2 and CH4 emissions, in metric tons CO2e for each gas,
from all distribution services combined.

(17)  *	*	*

(v)   For each EOR pump, report annual CO2 and CH4 emissions, expressed
in metric tons CO2e for each gas.

(vi)  A unique name or ID for the EOR pump.

(18)  For EOR hydrocarbon liquids dissolved CO2 for each sub-basin
category (refer to Equation W-38 of §98.233), report the following:

*	*	*	*	*

(iii)  Report annual CO2 emissions at the sub-basin level, expressed in
metric tons CO2e.

(19)  *	*	*

(iii)  Report annual CO2, CH4, and N2O emissions at from external fuel
combustion units with a rated heat capacity larger than 5 mmBtu/hr,
expressed in metric tons CO2e for each gas, by type of unit.

*	*	*	*	* 

(vi)  Report annual CO2, CH4, and N2O emissions from internal combustion
units, expressed in metric tons CO2e for each gas, by type of unit. 

*	*	*	*	*

(e)	For onshore petroleum and natural gas production, report the average
API gravity, average gas to oil ratio, and average low pressure
separator pressure for each sub-basin category.

17.  Section 98.237 is amended by adding paragraph (e) to read as
follows:

§98.237  Records that must be retained.

*	*	*	*	*

	(e) The records required under §98.3(g)(2)(i) shall include an
explanation of how company records, engineering estimation, or best
available information are used to calculate each applicable parameter
under this subpart.

18.  Section 98.238 is amended by: 

a.  Revising the definitions of “Facility with respect to natural gas
distribution for purposes of this subpart and subpart A”, “Facility
with respect to onshore petroleum and natural gas production for
purposes of this subpart and for subpart A”, “Farm Taps”, and
“Transmission pipeline”.

b.  Adding definitions of “Associated with a single well-pad”,
“Distribution pipeline”, “Flare”, “Forced extraction”,
“Horizontal well”, ”Natural gas”, “Metering-regulating
station”, “Pressure groupings”, “Sub-basin category”,
“Transmission-distribution transfer station”, “Tubing diameter
groupings”, “Tubing systems”, “Vertical well”, and “Well
testing venting and flaring”.

c.  Removing the definition of “Field”.

The revisions read as follows:

§98.238  Definitions.

*	*	*	*	*

Associated with a single well-pad means associated with the hydrocarbon
stream as produced from one or more wells located on that single
well-pad.  The association ends where the stream from a single well-pad
is combined with streams from one or more additional single well-pads,
where the point of combination is located off that single well-pad. 
This does not include storage and condensate tanks that are located
downstream of the point of combination.  

*	*	*	*	*

Distribution pipeline means a pipeline that is designated as such by the
Pipeline and Hazardous Material Safety Administration (PHMSA) 49 C.F.R.
§192.3.

*	*	*	*	*

Facility with respect to natural gas distribution for purposes of
reporting under this subpart and for the corresponding subpart A
requirements means the collection of all distribution pipelines and
metering-regulating stations that are operated by a Local Distribution
Company (LDC) within a single state that is regulated as a separate
operating company by a public utility commission or that are operated as
an independent municipally-owned distribution system.

Facility with respect to onshore petroleum and natural gas production
for purposes of reporting under this subpart and for the corresponding
subpart A requirements means all petroleum or natural gas equipment on a
well-pad or associated with a well-pad and CO2 EOR operations that are
under common ownership or common control including leased, rented, or
contracted activities by an onshore petroleum and natural gas production
owner or operator and that are located in a single hydrocarbon basin as
defined in §98.238.  Where a person or entity owns or operates more
than one well in a basin, then all onshore petroleum and natural gas
production equipment associated with all wells that the person or entity
owns or operates in the basin would be considered one facility.

Farm Taps are pressure regulation stations that deliver gas directly
from transmission pipelines to generally rural customers.  In some cases
a nearby LDC may handle the billing of the gas to the customer(s). 

*	*	*	*	*

Flare, for the purposes of subpart W, means a combustion device, whether
at ground level or elevated, that uses an open or closed flame to
combust waste gases without energy recovery.  

*	*	*	*	*

Forced extraction of natural gas liquids means removal of ethane or
higher carbon number hydrocarbons existing in the vapor phase in natural
gas, by removing ethane or heavier hydrocarbons derived from natural gas
into natural gas liquids by means of a forced extraction process. 
Forced extraction processes include but are not limited to
refrigeration, absorption (lean oil), cryogenic expander, and
combinations of these processes.  Forced extraction does not include in
and of itself; natural gas dehydration, or the collection or gravity
separation of water or hydrocarbon liquids from natural gas at ambient
temperature or heated above ambient temperatures, or the condensation of
water or hydrocarbon liquids through passive reduction in pressure or
temperature, or portable dewpoint suppression skids.  

*	*	*	*	*

Horizontal well means a well bore that has a planned deviation from
primarily vertical to a primarily horizontal inclination or declination
tracking in parallel with and through the target formation.

*	*	*	*	*

	Natural gas means a naturally occurring mixture or process derivative
of hydrocarbon and non-hydrocarbon gases found in geologic formations
beneath the earth’s surface, of which its constituents include, but
are not limited to, methane, heavier hydrocarbons and carbon dioxide. 
Natural gas may be field quality, pipeline quality, or process gas.  

Metering-regulating station means a station that meters the flowrate,
regulates the pressure, or both, of natural gas in a natural gas
distribution facility.  This does not include customer meters, customer
regulators, or farm taps. 

*	*	*	*	*

Pressure groupings are defined as follows: less than or equal to 25
psig; greater than 25 psig and less than or equal to 60 psig; greater
than 60 psig and less than or equal to 110 psig; greater than 110 psig
and less than or equal to 200 psig; and greater than 200 psig.

*	*	*	*	*

ermeability, and unconventional with ≤0.1 millidarcy permeability. 
Unconventional formation types are either shale, coal seam, or other
tight reservoir rock.  Wells producing from more than one unconventional
formation type shall be classified into only one type based on the
formation with the most contribution to production as determined by
engineering knowledge.  Unconventional wells producing in two or more
formation types  of “shale and coal seam”, “shale and other
tight”, or “shale, coal seam, and other tight”; are considered
shale.  In addition, unconventional wells producing in “coal seam and
other tight" formations are considered coal.

Transmission-distribution (TD) transfer station means a meter-regulating
station where a local distribution company takes part or all of the
natural gas from a transmission pipeline and puts it into a distribution
pipeline.  

Transmission pipeline means a Federal Energy Regulatory Commission
rate-regulated Interstate pipeline, a state rate-regulated Intrastate
pipeline, or a pipeline that falls under the “Hinshaw Exemption” as
referenced in section 1(c) of the Natural Gas Act, 15 U.S.C. 717-717
(w)(1994) .

Tubing diameter groupings are defined as follows:  less than or equal to
1 inch; greater than 1 inch and less than 2 inch; and greater than or
equal to 2 inch.

Tubing systems means piping equal to or less than one half inch diameter
as per nominal pipe size.

*	*	*	*	*

Vertical well means a well bore that is primarily vertical but has some
unintentional deviation or one or more intentional deviations to enter
one or more subsurface targets that are off-set horizontally from the
surface location, intercepting the targets either vertically or at an
angle.

Well testing venting and flaring means venting and/or  flaring of
natural gas at the time the production rate of a well is determined
(i.e., the well testing) through a choke (an orifice restriction).  If
well testing is conducted immediately after well completion or workover,
then it is considered part of well completion or workover.

19.  Table W-7 to subpart W is amended by:

a.  Revising the entries for “Leaker Emission Factors—Above Grade
M&R at City Gate1 Stations Components, Gas Service,” “Population
Emission Factors - Below Grade M&R2 Components, Gas Service3,”
“Population Emission Factors - Distribution Mains, Gas Service4,”
and “Population Emission Factors - Distribution Services, Gas
Service5.”

b.  Removing Footnote 1.

c.  Redesignating Footnotes 2, 3, 4, and 5 as Footnotes 1, 2, 3, and 4.

The revisions read as follows:

*	*	*	*	*	*	*

Leaker Emission Factors – Transmission-distribution Transfer Station1 

Components, Gas Service

*	*	*	*	*	*	*

Population Emission Factors - Below Grade Metering-Regulating station1
Components, Gas Service2

*	*	*	*	*	*	*

Population Emission Factors - Distribution Mains, Gas Service3 

*	*	*	*	*	*	*

Population Emission Factors - Distribution Services, Gas Service4

*	*	*	*	*	*	*



1 Excluding customer meters.

2 Emission Factor is in units of "scf/hour/station."

3 Emission Factor is in units of "scf/hour/mile."

4 Emission Factor is in units of “scf/hour/number of services.”



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

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

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

	

 

 

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

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


  PAGE  42  of   NUMPAGES  42 

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

   PAGE  137  of   NUMPAGES  210 

Page   PAGE  197  of   NUMPAGES  210 

Page   PAGE  138  of   NUMPAGES  210 

