[Federal Register: April 12, 2010 (Volume 75, Number 69)]
[Proposed Rules]
[Page 18607-18650]
[DOCID:fr12ap10-21]

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Part III

Environmental Protection Agency

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40 CFR Part 98

Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas
Systems; Proposed Rule

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 98

[EPA-HQ-OAR-2009-0923; FRL-9131-1]
RIN 2060-AP99

Mandatory Reporting of Greenhouse Gases: Petroleum and Natural
Gas Systems

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: EPA is proposing a supplemental rule to require reporting of
greenhouse gas (GHG) emissions from petroleum and natural gas systems.
Specifically, the proposed supplemental rulemaking would require
emissions reporting from the following industry segments: Onshore
petroleum and natural gas production, offshore petroleum and natural
gas production, natural gas processing, natural gas transmission
compressor stations, underground natural gas storage, liquefied natural
gas (LNG) storage, LNG import and export terminals, and distribution.
The proposed supplemental rulemaking does not require control of GHGs,
rather it requires only that sources above certain threshold levels
monitor and report emissions.

DATES: Comments must be received on or before June 11, 2010. There will
be one public hearing. The hearing will be on April 19, 2010 in
Arlington, VA and will begin at 8 a.m. local time and end at 5 p.m.
local time.

ADDRESSES: You may submit your comments, identified by docket EPA-HQ-
OAR-2009-0923 and/or RIN number 2060-AP99 by any of the following
methods:
     Federal eRulemaking Portal: http://www.regulations.gov.
Follow the online instructions for submitting comments.
     E-mail: GHG_Reporting_Rule_Oil_and_Natural_
<EMAIL_ADDRESS>Include EPA-HQ-OAR-2009-0923 and/or RIN number 2060-AP99
in the subject line of the message.
     Fax:<PHONE_NUMBER>.
     Phone:<PHONE_NUMBER>.
     Mail: Environmental Protection Agency, EPA Docket Center
(EPA/DC), Attention Docket EPA-HQ-OAR-2009-0923, Mail Code 2822T, 1200
Pennsylvania Avenue, NW., Washington, DC 20460.
     Hand/Courier Delivery: EPA Docket Center Public Reading
Room, Room 3334, EPA West Building, Attention Docket EPA-HQ-OAR-2009-
0923, 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-
2009-0923. 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 CBI or
other information whose disclosure is restricted by statute. Do not
submit information that you consider to be CBI or otherwise protected
through http://www.regulations.gov or e-mail. The http://
www.regulations.gov Web site is an ``anonymous access'' system, which
means EPA will not know your identity or contact information unless you
provide it in the body of your comment. If you send an e-mail comment
directly to EPA without going through http://www.regulations.gov your
e-mail address will be automatically captured and included as part of
the comment that is placed in the public docket and made available on
the Internet. If you submit an electronic comment, EPA recommends that
you include your name and other contact information in the body of your
comment and with any disk or CD-ROM you submit. If EPA cannot read your
comment due to technical difficulties and cannot contact you for
clarification, EPA may not be able to consider your comment. Electronic
files should avoid the use of special characters, any form of
encryption, and be free of any defects or viruses.
    Docket: All documents in the docket are listed in the http://
www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, will be publicly available only in hard copy.
Publicly available docket materials are available either electronically
in http://www.regulations.gov or in hard copy at the Air Docket, EPA's
Docket Center, Public Reading Room, EPA West Building, Room 3334, 1301
Constitution Ave., NW., Washington, DC 20004. 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 GENERAL 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:<PHONE_NUMBER>; fax number:<PHONE_NUMBER>; e-mail
address<EMAIL_ADDRESS>For technical information contact the
Greenhouse Gas Reporting Rule Hotline at telephone number: (877) 444-
1188; or e-mail<EMAIL_ADDRESS>To obtain information about the public
hearings or to register to speak at the hearings, please go to http://
www.epa.gov/climatechange/emissions/ghgrulemaking.html. Alternatively,
contact Carole Cook at<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION: EPA first proposed Mandatory GHG Reporting
requirements for petroleum and natural gas systems (under 40 CFR, part
98, subpart W) in April 2009. EPA received a substantial number of
comments on this initial proposal for petroleum and natural gas
systems. For this reason, EPA decided not to finalize the rule for
petroleum and natural gas systems, and instead to propose a
supplemental rule.
    EPA reviewed and considered comments submitted on the previous
proposal in drafting this proposed supplemental rulemaking. However, as
this is a new proposal, EPA is not here responding to comments on the
earlier version of this rule. Any comments must be submitted as
provided herein, to be considered. A more detailed background
concerning the subpart W rulemaking and proposed changes can be found
in section II-A.
    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, 1200 Pennsylvania
Ave., NW., Washington, DC 20460, telephone<PHONE_NUMBER>, e-mail:
<EMAIL_ADDRESS>    Although as indicated above, EPA previously proposed a version of
this rule, that proposal never became final. This is a newly proposed
rule and comments which were submitted on the earlier version of the
rule are not being considered in the context of this rule. Any parties
interested in commenting must do so at this time.
    Regulated Entities. The Administrator determined that this action
is subject to the provisions of Clean Air Act (CAA) section 307(d). See
CAA section

307(d)(1)(V) (the provisions of section 307(d) apply to ``such other
actions as the Administrator may determine.''). This is a proposed
regulation. If finalized, these regulations would affect owners or
operators of petroleum and natural gas systems. Regulated categories
and entities include those listed in Table 1 of this preamble:

                                                   Table 1--Examples of Affected Entities by Category
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                Source Category                   NAICS                                   Examples of affected facilities
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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.
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    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. Table 1 of this preamble lists the types of
facilities that EPA is now aware could be potentially affected by the
reporting requirements. Other types of facilities listed in the table
could also be subject to reporting requirements. To determine whether
you are affected by this action, you should carefully examine the
applicability criteria found in proposed 40 CFR part 98, subpart A or
the relevant criteria in the sections related to petroleum and natural
gas systems. 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.
    Many facilities that are affected by the proposed supplemental rule
have GHG emissions from multiple source categories listed in Table 1 of
this preamble. Table 2 of this preamble has been developed as a guide
to help potential reporters in the petroleum and natural gas industry
subject to the proposed rule identify the source categories (by
subpart) that they may need to (1) consider in their facility
applicability determination, and/or (2) include in their reporting. The
table should only be seen as a guide. Additional subparts in 40 CFR
part 98 may be relevant for a given reporter. Similarly, not all listed
subparts are relevant for all reporters.

                                Table 2--Source Categories and Relevant Subparts
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        Source category                 Other Subparts recommended for review to determine  applicability
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Petroleum and Natural Gas        40 CFR part 98, subpart C.
 Systems.
                                 40 CFR part 98, subpart Y.
                                 40 CFR part 98, subpart MM.
                                 40 CFR part 98, subpart NN.
                                 40 CFR part 98, subpart PP.
                                 40 CFR part 98, subpart RR (proposed).
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    Acronyms and Abbreviations. The following acronyms and
abbreviations are used in this document.

ASTM American Society for Testing and Materials
CAA Clean Air Act
CBI confidential business information
cf cubic feet
CFR Code of Federal Regulations
CH4 methane
CO2 carbon dioxide
CO2e CO2-equivalent
EO Executive Order
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
GHG greenhouse gas
GWP global warming potential
ICR information collection request
IPCC Intergovernmental Panel on Climate Change
kg kilograms
LDCs local natural gas distribution companies
LNG liquefied natural gas
LPG liquefied petroleum gas
MRR mandatory GHG reporting rule
MMTCO2e million metric tons carbon dioxide equivalent
N2O nitrous oxide
NAICS North American Industry Classification System
NGLs natural gas liquids
OMB Office of Management and Budget
QA quality assurance
QA/QC quality assurance/quality control
RFA Regulatory Flexibility Act
RGGI Regional Greenhouse Gas Initiative
SSM startup, shutdown, and malfunction
TCR The Climate Registry
TSD technical support document
U.S. United States
UMRA Unfunded Mandates Reform Act of 1995
VOC volatile organic compound(s)
WCI Western Climate Initiative

Table of Contents

I. Background
    A. Organization of this Preamble
    B. Background on the Proposed Rule
    C. Legal Authority
    D. Relationship to Other Federal, State and Regional Programs
II. Rationale for the Reporting, Recordkeeping and Verification
Requirements
    A. Overview of Proposal
    B. Summary of the Major Changes Since Initial Proposal
    C. Definition of the Source Category
    D. Selection of Reporting Threshold
    E. Selection of Proposed Monitoring Methods
    F. Selection of Procedures for Estimating Missing Data
    G. Selection of Data Reporting Requirements
    H. Selection of Records That Must Be Retained
III. Economic Impacts of the Proposed Rule
    A. How were compliance costs estimated?
    B. What are the costs of the proposed rule?
    C. What are the economic impacts of the proposed rule?
    D. What are the impacts of the proposed rule on small
businesses?
    E. What are the benefits of the proposed rule for society?
IV. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and 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. Organization of This Preamble

    This preamble is broken into several large sections, as detailed
above in the Table of Contents. The paragraphs below describe the
layout of the preamble and provide a brief summary of each section.
    The first section of this preamble contains the basic background
information about the origin of this proposed supplemental rulemaking,
including a discussion of the initial proposed rule for petroleum and
natural gas systems. This section also discusses EPA's use of our legal
authority under the Clean Air Act to collect the proposed data, and the
benefits of collecting the data. The relationship between the mandatory
GHG reporting program and other mandatory and voluntary reporting
programs at the national, regional and State level also is discussed.
    The second section of this preamble summarizes the general
provisions of this proposed supplemental rulemaking for petroleum and
natural gas systems. It also highlights the major changes between the
initial proposed rule and the supplemental rule that we are proposing
today, including changes in the scope of the proposed rule and the
monitoring methods proposed. This section then provides a brief summary
of, and rationale for, selection of key design elements. Specifically,
this section describes EPA's rationale for (i) the definition of the
source category (ii) selection of reporting thresholds (iii) selection
of monitoring methods, (iv) missing data procedures (v) proposed data
reporting requirements, and (vi) recordkeeping requirements. Thus, for
example, there is a specific discussion regarding appropriate
thresholds, monitoring methodologies and reporting and recordkeeping
requirements for each segment of the petroleum and natural gas industry
proposed for inclusion in the rule: onshore petroleum and natural gas
production, offshore petroleum and natural gas production, natural gas
processing, natural gas transmission compressor stations, natural gas
underground storage, LNG storage, LNG import and export terminals, and
distribution. EPA describes the proposed options for each design
element, as well as the other options considered. Throughout this
discussion, EPA highlights specific issues on which we solicit comment.
Please refer to the specific source category of interest for more
details.
    The third section provides the summary of the cost impacts,
economic impacts, and benefits of this proposed rule from the Economic
Analysis. Finally, the last section discusses the various statutory and
executive order requirements applicable to this proposed rulemaking.

B. Background on the Proposed Rule

    The Final Mandatory GHG Reporting Rule (``Final MRR''), (40 CFR
part 98) was signed by EPA Administrator Lisa Jackson on September 22,
2009 and published in the Federal Register on October 30, 2009 (74 FR
209 (October 30, 2009) pp. 56260-56519). The Final MRR which is
effective on December 29, 2009 included reporting of GHGs from
facilities and suppliers that EPA determined met the criteria in the
2008 Consolidated Appropriations Act.\1\ These source categories
capture approximately 85 percent of U.S. GHG emissions through
reporting by direct emitters as well as suppliers of fossil fuels and
industrial gases. There are, however, many additional types of data and
reporting that the Agency deems important and necessary to address an
issue as large and complex as climate change (e.g. indirect emissions
from electricity use). In that sense, one could view the Final MRR (40
CFR part 98) as focused on certain sources of emissions and upstream
suppliers. For information on existing programs at the Federal,
Regional and State levels that also collect valuable information to
inform and implement policies necessary to address climate change,
relationship of the Final MRR to EPA and U.S. government climate change
efforts and to other State and Regional Programs, see the Preamble to
the Final MRR.
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    \1\ Consolidated Appropriations Act, 2008, Public Law 110-161,
121 Stat. 1844, 2128.
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    In the April 2009 proposed mandatory GHG reporting rule the
petroleum and natural gas systems subcategory was included as Subpart
W. EPA received a number of lengthy, detailed comments regarding this
subpart W proposal. Some comments were focused on the significant cost
burden that the April 2009 proposed rule would impose on petroleum and
natural gas systems, whereas others focused on whether certain sources,
such as onshore production and distribution, that were not included in
the initial proposal, should be included. EPA recognized the concerns
raised by stakeholders, and decided not to finalize subpart W with the
Final MRR, but instead to propose a new supplemental rule for petroleum
and natural gas systems. This proposed supplemental rule incorporates a
number of changes including, but not limited to, different
methodologies that provide improved emissions coverage at a lower cost
burden to facilities than would have been covered under the initial
proposed rule; the inclusion of onshore production and distribution
facilities; and separate definitions for ``vented'' and ``fugitive''
emissions. As noted earlier, stakeholders should submit comments in the
context of this new proposed supplemental rule.
    This proposed supplemental rule 40 CFR part 98, subpart W requires
annual reporting of fugitive and vented carbon dioxide (CO2)
and methane (CH4) emissions from petroleum and natural gas
systems facilities, as well as combustion-related CO2,
CH4, and nitrous oxide (N2O) emissions from
flares at those facilities, following the methods outlined in the
proposal. This proposed rule would also establish appropriate
thresholds and frequency for reporting, as well as provisions to ensure
the accuracy of emissions through monitoring, reporting and
recordkeeping requirements.
    This proposed rule applies to facilities in specific segments of
the petroleum and natural gas industry that emit GHGs greater than or
equal to 25,000 metric tons of CO2 equivalent per year.
Reporting would be at the facility level.

C. Legal Authority

    EPA is proposing this rule under its existing CAA authority,
specifically authorities provided in section 114 of the CAA. As
discussed further below and in ``Mandatory Greenhouse Gas Reporting
Rule: EPA's Response to Public Comments, Legal Issues'' (EPA-HQ-OAR-
2008-0508-2264), EPA is not citing the FY 2008 Consolidated
Appropriations Act as the statutory basis for this action. While that
law required that EPA spend no less than $3.5 million on a rule
requiring the mandatory reporting of GHG emissions, it is the CAA, not
the Appropriations Act, that EPA is citing as the authority to gather
the information proposed by this rule.
    As stated in the Final MRR, 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 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 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.
    EPA notes that comments were submitted on the initial rule proposal
questioning EPA's authority under the Clean Air Act to collect
emissions information from certain offshore petroleum and natural gas
platforms. Some commenters argued that EPA does not have the authority
to collect emissions information from offshore platforms located in
areas of the Western Gulf because they are under the jurisdiction of
the Department of the Interior. They cited, among other things, the
Outer Continental Shelf Act, 43 U.S.C. 1334. Without opining on the
accuracy of the commenter's summary of OCSLA or other law, we note that
even the commenter describes these authorities as relating to the
regulation of air emissions. Today's proposal does not regulate GHG
emissions; rather it gathers information to inform EPA's evaluation of
various CAA provisions. Moreover, EPA's authority under CAA Section 114
is broad, and extends to any person ``who the Administrator believes
may have information necessary for the purposes'' of carrying out the
CAA, even if that person is not subject to the CAA. Indeed, by
specifically authorizing EPA to collect information from both persons
subject to any requirement of the CAA, as well as any person who the
Administrator believes may have necessary information, Congress clearly
intended that EPA could gather information from a person not otherwise
subject to CAA requirements. EPA is comprehensively considering how to
address climate change under the CAA, including both regulatory and
non-regulatory options. The information from these and other offshore
platforms will inform our analyses, including options applicable to
emissions of any offshore platforms that EPA is authorized to regulate
under the CAA.
    EPA is proposing to amend 40 CFR 98.2(a) so that the final MRR
applies to facilities located in the United States and on or under the
Outer Continental Shelf. These revisions are necessary to ensure that
any petroleum or natural gas platforms located on our under the Outer
Continental Shelf of the United States would be required to report
under this rule. In addition, EPA is proposing revisions to the
definition of United States to clarify that the United States includes
the territorial seas. Other facilities located offshore of the United
States covered by the mandatory reporting program at 40 CFR part 98
would also be affected by this change in the definition of United
States. Revising the definition of United States will also ensure that
facilities located offshore of the United States that are injecting
CO2 into sub-seabed for long-term containment will also be
required to report data regarding greenhouse gases. EPA is proposing a
separate rule on geologic sequestration and any comments specific to
that issue should be directed to the Agency on that rulemaking not this
one. Finally, in addition to the change to the definition of United
States, EPA is adding a definition of ``Outer Continental Shelf.'' This
definition is drawn from the definition in the U.S. Code. Together,
these changes make clear that the Mandatory GHG Reporting Rule applies
to facilities on land, in the territorial seas, or on or under the
Outer Continental Shelf, of the United States, and that otherwise meet
the applicability criteria of the rule.
    For further information about EPA's legal authority, see the
proposed and final MRR.

D. Relationship to Other Federal, State and Regional Programs

    In developing the initial proposal for mandatory reporting from
petroleum and natural gas systems that was released in April 2009, as
well as this supplemental proposed rulemaking, EPA reviewed monitoring
methods included in international guidance (e.g., Intergovernmental
Panel on Climate Change), as well as Federal voluntary programs (e.g.,
EPA Natural Gas STAR Program and the U.S. Department of Energy
Voluntary Reporting of Greenhouse Gases Program (1605(b)), corporate
protocols (e.g., World Resources Institute and World Business Council
for Sustainable Development GHG Protocol) and industry guidance (e.g.,
methodological guidance from the American Petroleum Institute, the
Interstate Natural Gas Association of America, and the American Gas
Association).
    EPA also reviewed State reporting programs (e.g., California and
New Mexico) and Regional partnerships (e.g., The Climate Registry, the
Western Regional Air Partnership). These are important programs that
not only led the way in reporting of GHG emissions before the Federal
government acted but also assist in quantifying the GHG reductions
achieved by various policies. Many of these programs collect different
or additional data as compared to this proposed rule. For example,
State programs may establish lower thresholds for reporting, request
information on areas not addressed in EPA's reporting rule, or include
different data elements to support other programs (e.g., offsets). For
further discussion on the relationship of this proposed rule to other
programs, refer to the preamble to the Final MRR.

II. Rationale for the Reporting, Recordkeeping and Verification
Requirements

A. Overview of Proposal

    The U.S. petroleum and natural gas industry encompasses hundreds of
thousands of wells, hundreds of processing facilities, and over a
million miles of transmission and distribution pipelines. This proposed
rule would apply to the calculation and reporting of vented, fugitive,
and flare combustion emissions from selected equipment at the following
facilities that emit equal to or greater than 25,000 metric tons of
CO2 equivalent per year from source categories covered by
the mandatory GHG reporting rule: offshore petroleum and natural gas
production facilities, onshore petroleum and natural gas production
facilities (including enhanced oil recovery (EOR)), onshore natural gas
processing facilities, onshore natural gas transmission compression
facilities, onshore natural gas storage facilities, LNG storage
facilities, LNG import and export facilities and natural gas
distribution facilities owned or operated by local distribution
companies (LDCs). This proposal does not address the production of gas
from landfills or manure management systems. Methods and reporting
procedures for stationary combustion emissions other than flares at
petroleum and natural gas industry facilities are covered under Subpart
C of the Final MRR.
    This proposed supplemental rule incorporates a number of different
methodologies to provide improved emissions coverage at a lower cost
burden to affected facilities, as compared to the initial proposed
rule. In this supplemental proposal, EPA is requiring the use of direct
measurement of emissions for only the most significant emissions
sources where other options are not available, and proposing the use of
engineering estimates, emissions modeling software, and leak detection
and publicly available emission factors for most other vented and
fugitive sources. For smaller fugitive and inaccessible to plain view
sources, component count and population emissions factors are proposed.
In the case of offshore platforms, EPA is recommending that

emissions sources identified under the Minerals Management Services
(MMS) GOADS (Gulfwide Offshore Activities Data System) be used for
reporting, and the GOADS process be extended to platforms in other
Federal regions (i.e., California and Alaska) and in State waters. The
alternative methodologies proposed in this rule will provide similar or
better estimation of vented and fugitive CH4 and
CO2 emissions in the petroleum and gas industry, while
significantly reducing industry burden.
    Under this supplemental proposal, facilities not already reporting
but required to report under subpart W would begin data collection in
2011 following the methods outlined in the proposed rule, and submit
data to EPA by March 31, 2012.
    EPA would require reporting of calendar year 2011 emissions in 2012
because the data are crucial to the timely development of future GHG
policy and regulatory programs. In the Appropriation Act, Congress
requested EPA to develop this reporting program on an expedited
schedule, and Congressional inquiries along with public comments
reinforce that data collection for calendar year 2011 is a priority.
Delaying data collection until calendar year 2012 would mean the data
would not be received until 2013, which would likely be too late for
many ongoing GHG policy and program development needs.
    EPA considered, but decided not to propose, the use of best
available monitoring methods for part (e.g., the first three months) or
all of the first year of data collection. EPA concluded that the time
period that would be allowed under this schedule is sufficient to allow
facilities to implement the monitoring methods that would be required
by the proposed rule. In general, the proposed monitors are widely
available and are not time consuming to install. Further, some of the
monitoring methods (e.g., use of emission factors) may not require the
installation of any monitoring equipment. Finally, the emissions
assessment may be done at any time during the year, and measurements do
not necessarily need to be undertaken during the first quarter.
    EPA seeks comment on the proposal not to allow use of best
available monitoring methods for part or all of the first year of data
collection. Further, if commenters recommend that EPA allow the use of
best available monitoring methods for a designated time period (e.g.,
three months), EPA seeks comments on whether requests for use of best
available monitoring methods should only be approved for parameters
subject to direct measurement, or also in cases where engineering
calculations and/or emission factors are used.
    Amendments to the General Provisions. In a separate rulemaking
package that was recently published (March 16, 2010), EPA issued minor
harmonizing changes to the general provisions for the GHG reporting
rule (40 CFR part 98, subpart A) to accommodate the addition of source
categories not included in the 2009 final rule (e.g., subparts proposed
in April 2009 but not finalized in 2009, any new subparts that may be
proposed in the future). The changes update 98.2(a) on rule
applicability and 98.3 regarding the reporting schedule to accommodate
any additional subparts and the schedule for their reporting
obligations (e.g., source categories finalized in 2010 would not begin
data collection until 2011 and reporting in 2012).
    In particular, we restructured 40 CFR 98.2(a) to move the lists of
source categories from the text into tables. A table format improves
clarity and facilitates the addition of source categories that were not
included in calendar year 2010 reporting and would begin reporting in
future years. A table, versus list, approach allows other sections of
the rule to be updated automatically when the table is updated; a list
approach requires separate updates to the various list references each
time the list is changed. In addition to reformatting the 98.2(a)(1)-
(2) lists into tables, other sections of subpart A were reworded to
refer to the source category tables because the tables make it clear
which source categories are to be considered for determining the
applicability threshold and reporting requirements for calendar years
2010, 2011, and future years.
    Because facilities with petroleum and natural gas systems (as
defined in proposed 40 CFR part 98, subpart W) would be subject to the
rule if facility emissions exceed 25,000 metric tons CO2e
per year, in today's rule we are proposing to add this source category
to those threshold categories referenced from 40 CFR 98.2(a)(2) whether
the reference is to a list or a table.\2\
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    \2\ Since we are proposing to change the list of covered
subcategories to tables, we are not providing regulatory text in
this proposal because the preamble is clear.
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    In today's proposal, we also propose to amend 40 CFR 98.6 to add
definitions for several terms used in proposed 40 CFR part 98, subpart
W and to clarify the meaning of certain terms for purposes of subpart
W. We also propose to amend 40 CFR 98.7 (incorporation by reference) to
include standard methods used in proposed subpart W. In particular, we
propose to incorporate by reference the AAPG-CSD Geologic Code
Provinces Code Map available from The American Association of Petroleum
Geologists Bulletin, Volume 75, No. 10 (October 1991) pages 1644-1651.
It would be used to define the geographic boundaries for reporting of
onshore oil and gas production systems. We also proposed to incorporate
by reference models, including Glycalc and E&P Tanks that would be used
to calculate emissions and were not developed by the Federal
government.

B. Summary of the Major Changes Since Initial Proposal

    Mandatory GHG reporting requirements were proposed for Petroleum
and Natural Gas Systems under Subpart W in April 2009 along with a
number of other sectors of the economy. As noted in the Preamble to the
Final MRR, EPA received a number of lengthy, detailed comments
regarding Petroleum and Natural Gas Systems. In total, EPA received
comments from over 80 organizations and over 1,200 pages of formal
comments on the Petroleum and Gas Systems Initial Proposed Rule. Some
comments proposed simplified alternatives to the proposed reporting
requirements based on the potential that the proposed requirements
would entail significant burden and cost. Other comments addressed
whether to include onshore production and the distribution segment,
which were excluded from the initial proposal as EPA sought comments on
approaches for the level of reporting of fugitive and vented GHG
emissions from these segments (e.g., facility or corporate).
    EPA has reviewed the comments and issues and suggestions raised by
stakeholders within and outside the petroleum and natural gas industry
related to emissions coverage and the level of cost burden in this
sector. In response, EPA is proposing a new supplemental rule for
Petroleum and Natural Gas Systems. This proposed supplemental rule now
incorporates all segments of the petroleum and gas industry, adding
onshore production and distribution.
    Total fugitive, vented and combustion emissions estimated to be
covered in this supplemental proposed rulemaking amount to 351
MMTCO2e; 272 MMTCO2e from fugitive and vented
emissions and 79 MMTCO2e from combustion emissions.\3\
Fugitive and

vented emissions estimates included in the supplemental proposed
rulemaking are significantly higher than the 131 MMTCO2e
reported in the 2008 U.S. Inventory of Greenhouse Gases, due to the
inclusion of items believed to be under-reported in the inventory
(discussed further below).
---------------------------------------------------------------------------

    \3\ Some petroleum and natural gas facilities will already be
required to report emissions from stationary combustion under the
MRR that was signed in September 2009. This proposed petroleum and
natural gas subpart will require additional facilities to report to
the MRR that are not currently required to report. These facilities
will have to report combustion, fugitive and vented emissions. These
incremental combustion emissions are estimated at 79
MMTCO2e.
---------------------------------------------------------------------------

    Table W-1 summarizes the estimated fugitive, vented and combustion
emissions for the segments included in the initial proposal and the
added segments of onshore production and distribution. Additional
details can be found in the Economic Impact Analysis for the Mandatory
Reporting of Greenhouse Gas Emissions under Subpart W Supplemental Rule
(EPA-HQ-OAR-2009-0923).

       Table W-1--Fugitive/Vented and Combustion Emissions From Petroleum and Natural Gas Systems, MMTCO2e
----------------------------------------------------------------------------------------------------------------
                                                                                Fugitive and
                                                                   Fugitive and       vented        Combustion
                                                                      vented        emissions:      emissions:
                             Segment                                emissions:     Supplemental    Supplemental
                                                                      Initial        proposed        proposed
                                                                   proposed rule    rulemaking      rulemaking
----------------------------------------------------------------------------------------------------------------
Initial Proposed Rule Six Segments..............................              85            94.3             9.8
Onshore Production..............................................              NA           154.9            69.3
Natural Gas Distribution........................................              NA            22.7              NA
                                                                 -----------------------------------------------
    Total Emissions.............................................              85           271.9        \1\ 79.1
----------------------------------------------------------------------------------------------------------------
\1\ This estimate reflects only incremental combustion emissions (i.e., only those combustion emissions from
  facilities above and beyond what will already be required to be reported under the Final MRR). For example,
  combustion-related emissions ftrom many natural gas processing plants are already required to be reported
  under subpart C and are therefore not included here. The combustion estimate also includes combustion
  emissions from flares.

    Inclusion of onshore production and distribution results in
estimated fugitive and vented emissions that are more than triple the
estimated emissions in the initial rule proposal for petroleum and
natural gas systems.
    In addition to expanding emissions coverage under the proposed
supplemental rule, EPA has assessed a number of alternative
methodologies that were either recommended by commenters or are known
to provide effective quantification of emissions at a significantly
lower cost burden. The changes include the use of:
     Limited use of fugitive leak detection.
     Leaker factors to quantify detected fugitive emissions.
     Population factors and component count for fugitive
emissions that are widely scattered or inaccessible to plain view.
     Use of existing MMS GOADS methods and calculated emissions
for offshore production facilities.
     Modeling software to quantify glycol dehydrator and tank
emissions.
     Engineering estimation for well venting from liquids
unloading.
     Engineering estimation for well venting from completions
and workovers.
     Engineering estimation for well testing and flaring.
     Engineering estimation for flaring emissions.
     Limited sampling to determine gas composition.
    Another significant change in the proposed supplemental rule is the
use of the term ``fugitives''. The initial rule proposal from April
2009 included both vented and fugitive emissions sources, and
collectively defined both sources as ``fugitive''. EPA received a large
number of comments from industry stakeholders and others indicating
that this definition created confusion. Hence EPA is defining vented
emissions separately from fugitives in the supplemental proposed
rulemaking. For this supplemental rulemaking, emissions from the
petroleum and natural gas industry are defined as (1) vented emissions,
which include intentional or designed releases of CH4 and/or
CO2 containing natural gas or hydrocarbon gas (not including
stationary combustion flue gas) from emissions sources including, but
not limited to, process designed flow to the atmosphere through seals
or vent pipes, equipment blowdown for maintenance, and direct venting
of gas used to power equipment (such as pneumatic devices). In
addition, this supplemental rule includes (2) fugitive emissions, or
unintentional emissions, which are defined to include those emissions
which could not reasonably pass through a stack, chimney, vent, or
other functionally-equivalent opening. This supplemental rule also
includes (3) flare combustion emissions, which include CH4,
CO2 and N2O emissions resulting from combustion
of gas in flares. EPA seeks comment on the use of the term ``equipment
leak'' versus ``fugitive'' and ``vented'' as defined in the proposed
supplemental rule.

C. Definition of the Source Category

    EPA discusses here the general approach used in identifying the key
segments of the petroleum and natural gas industry that would be
required to report under the proposal. This general discussion is
followed by a specific discussion for each industry segment.
    One factor EPA considered in assessing the applicability of certain
petroleum and natural gas industry emissions in the proposed rule is
the definition of a facility. In other words, what physically
constitutes a facility? This definition is important to determine the
reporting entity, to ensure that delineation is clear, and to minimize
double counting or omissions of emissions. For some segments of the
industry (e.g., onshore natural gas processing facilities, natural gas
transmission compression facilities, and offshore petroleum and natural
gas facilities), identifying the facility is clear since there are
physical boundaries and ownership structures that lend themselves to
identifying scope of reporting and responsible reporting entities. In
other segments of the industry (e.g., the pipelines between compressor
stations and onshore petroleum and natural gas production) such
distinctions are not as

straightforward. In defining a facility, EPA reviewed current
definitions used in the Clean Air Act (CAA), ISO definitions, comments
provided under the initial proposed rule, and current regulations
relevant to the industry. A complete description of our assessment can
be found in Greenhouse Gas Emissions from the Petroleum and Natural Gas
Industry: Background Technical Support Document (TSD) (EPA-HQ-OAR-2009-
0923).
    At the same time, EPA also decided that it was impractical to
include each of the over 160 different sources of vented and fugitive
CH4 and CO2 emissions in the petroleum and
natural gas industry. In response to comments received on the initial
proposed rule, EPA undertook a systematic review of each emissions
source included in the 2008 U.S. GHG Inventory in order to propose
reporting of only the most significant emissions sources (e.g.
emissions that account for the majority of oil and gas fugitive and
vented emissions). In determining the most relevant vented and fugitive
emissions sources for inclusion in this supplemental proposed
rulemaking, EPA considered the following criteria: The coverage of
emissions for the source category as a whole; the coverage of emissions
per unit of the source category; the feasibility of a viable monitoring
method, including direct measurement and engineering estimations; and
the number of facilities that would be required to report. Sources that
contribute significantly large emissions were considered for inclusion
in this supplemental proposed rulemaking, since they increase the
coverage of emissions reporting. Typically, at petroleum and gas
facilities, 80 percent or more of a facility's emissions come from
approximately 10 percent of the emissions sources. EPA used this
benchmark to reduce the number of emissions sources required for
reporting while keeping the reporting burden to a minimum. Sources in
each segment of the petroleum and natural gas industry were sorted into
two main categories: (1) The largest sources contributing to
approximately 80 percent of the emissions from the segment, and (2) the
sources contributing to the remaining 20 percent of the emissions from
that particular segment. EPA assigned sources into these two groups by
determining the emissions contribution of each emissions source to its
relevant segment of the petroleum and gas industry, listing the
emissions sources in a descending order, and identifying all the
sources at the top that contribute to approximately 80 percent of the
emissions. Generally, those sources that fell into approximately the
top 80 percent were considered for inclusion. Details of the analysis
can be found in Greenhouse Gas Emissions from the Petroleum and Natural
Gas Industry: Background TSD (EPA-HQ-OAR-2009-0923).
    The following is a brief discussion of the proposed emission
sources to be included and excluded based on our analysis. Additional
information can be found in Greenhouse Gas Emissions from the Petroleum
and Natural Gas Industry: Background TSD (EPA-HQ-OAR-2009-0923. Note
that this subpart of the GHG reporting rule addresses only vented,
fugitive and flare combustion emissions. As mentioned previously,
stationary combustion emissions are included in Subpart C of the Final
MRR Preamble.
Onshore Petroleum and Natural Gas Production
    The onshore petroleum and natural gas production segment uses wells
to extract raw natural gas, condensate, crude oil, and associated gas
from underground formations and inject CO2 for EOR.
Extraction includes several types of processes: Reservoir management,
primary recovery, secondary recovery such as down-hole pumps, water
flood or natural gas/nitrogen/immiscible CO2 injection, and
tertiary recovery such as using critical phase miscible CO2
injection. The largest sources of CH4 and CO2
emissions include, but are not limited to, natural gas driven pneumatic
devices and pumps, field crude oil and condensate storage tanks, glycol
dehydration units, releases and flaring during well completions, well
workovers, and well blowdowns for liquids unloading, releases and
flaring of associated gas, and blowdowns of compressors and EOR pumps.
    EPA is proposing to include the onshore petroleum and natural gas
production segment due to the fact that these operations represent a
significant emissions source, representing approximately 66 percent of
fugitive, vented and incremental\4\ combustion emissions from the
petroleum and natural gas segments covered by the proposed rule.
---------------------------------------------------------------------------

    \4\ The denominator includes total fugitive and vented
emissions, as well as any additional combustion related emissions
that will be required to be reported by the petroleum and natural
gas industry and that wasn't already covered in the final MRR.
---------------------------------------------------------------------------

    EPA considered a range of possible options for reporting emissions
from onshore petroleum and natural gas facilities. Although several
options for defining the facility were considered and described below,
EPA has determined that only two of the options are feasible: Basin-
level reporting and field-level reporting. For this supplemental
proposed rulemaking, EPA proposes that emissions from onshore petroleum
and natural gas production be reported at the basin level. The
reporting entity for onshore petroleum and natural gas production would
be the operating entity listed on the state well drilling permit, or a
state operating permit for wells where no drilling permit is issued by
the state, who operates onshore petroleum and natural gas production
wells and controls by means of ownership (including leased and rented)
and operation (including contracted) stationary and portable (as
defined in this Subpart) equipment located on all well pads within a
single hydrocarbon basin as defined by the American Association of
Petroleum Geologists (AAPG) three-digit Geological Province Code. The
equipment referenced above includes all structures associated with
wells used in the production, extraction, recovery, lifting,
stabilization, separation or treating of petroleum and/or natural gas
(including condensate) including equipment that is leased, rented or
contracted. This includes equipment such as compressors, generators or
storage facilities, piping (such as flowlines or intra-facility
gathering lines), and portable non-self-propelled equipment (such as
well drilling and completion equipment, workover equipment, gravity
separation equipment, auxiliary non-transportation-related equipment).
This also includes associated storage or measurement equipment and all
equipment engaged in gathering produced gas from multiple wells, EOR
operations using CO2, and all petroleum and natural gas
production operations located on islands, artificial islands or
structures connected by a causeway to land, an island, or artificial
island.
    Where more than one entity may hold the state well drilling permit,
or well operating permit where no drilling permit is issued by the
state, the permitted entities for the facility would be required to
designate one entity to report all emissions from the jointly
controlled facility. Where an operating entity holds more than one
permit to operate wells in a basin, then all onshore petroleum and
natural gas production well permits in their name in the basin,
including all equipment on the well pads, would be considered one
onshore petroleum and natural gas

production facility for purposes of reporting.
    There are at least two industry recognized definitions available
that identify hydrocarbon basins; one from the United State Geological
Survey (USGS) and the other from the AAPG. The AAPG geologic definition
is referenced to county boundaries and hence likely to be familiar to
the industry, i.e. if the owner or operator knows in which county their
well is located, then they know to which basin they belong. Basins are
mapped to county boundaries only to give a surface manifestation to the
underground geologic structures, thus making it easier to relate
surface facilities to basin underground geologic boundaries. On the
other hand, the USGS definition is based purely on the geology of the
hydrocarbon basin without consideration of state and county boundaries.
Hence using the USGS definition may make it more difficult to map
surface operations to a particular basin. Therefore, EPA is proposing
to use the AAPG definition of a basin. EPA seeks comments on the
availability of other appropriate standard basin level definitions that
could be applied for the purposes of this rule and their merits over
the AAPG definition.
    EPA is proposing a basin level approach, because the boundaries for
reporting are clearly defined and the approach covers approximately 81
percent of emissions from onshore petroleum and natural gas production.
    EPA evaluated and is taking comment on one alternative option for
reporting from onshore petroleum and natural gas production; field
level. Field level reporting would require aggregation of emissions
from all covered equipment at onshore petroleum and natural gas
production facilities at the field level, as opposed to the basin level
as described above. A typical field level definition is available from
the Energy Information Administration Oil and Gas Field Code Master. As
outlined in the Economic Impact Analysis for this proposed rule, the
field level option would result in a significantly lower coverage in
emissions, estimated at 55 percent in comparison to the basin level
coverage of 81 percent. In essence the two reporting options are not
different from a methodological point of view because both definitions
rely on geographical boundaries. Therefore, EPA has proposed the use of
a basin level definition to increase coverage. EPA seeks comments on
our decision to propose the basin level approach, and whether there
would be advantages to requiring reporting at the field level instead.
    In addition to basin and field level reporting, EPA considered one
other alternative approach for defining a facility for onshore
petroleum and natural gas production; individual well pads. This well
pad approach included all stationary and portable equipment operating
in conjunction with that well, including drilling rigs with their
ancillary equipment, gas/liquid separators, compressors, gas
dehydrators, crude oil heater-treaters, gas powered pneumatic
instruments and pumps, electrical generators, steam boilers and crude
oil and gas liquids stock tanks. This definition was analyzed with
available data including four cases to represent the full range of
petroleum and natural gas well pad operations ranging from
unconventional well drilling and operation starting in the beginning of
the year with higher emitting practices, to production at an associated
gas and oil well (no drilling) with minimal equipment and a vapor
recovery unit.
    EPA analyzed the average emissions associated with each of the four
well pad facility cases and determined that average emissions at these
operations were low (from about 370 metric tons of CO2e per
year to slightly less than 5,000 metric tons of CO2e per
year). This analysis shows that the threshold would have to be set at
less than 400 metric tons CO2e per year to capture the
largest possible amount of onshore production emissions (only 33
percent) which would result in close to 170,000 reporters. Additional
information can be found in Greenhouse Gas Emissions from the Petroleum
and Natural Gas Industry: Background TSD (EPA-HQ-OAR-2009-0923). If the
threshold was set at approximately 5,000 metric tons, EPA estimates
that the number of reporters would decrease significantly to
approximate 3,300 but the emission coverage would be only 6 percent.
Based on the results above, EPA did not consider the well pad
definition further in the Economic Impact Analysis.
Offshore Petroleum and Natural Gas Production
    Offshore petroleum and natural gas production is any platform
structure, affixed temporarily or permanently to offshore submerged
lands, that houses equipment to extract hydrocarbons from the ocean or
lake floor and that transfers such hydrocarbons to storage, transport
vessels, or onshore. In addition, offshore production includes
secondary platform structures and storage tanks associated with the
platform structure. GHG emissions result from sources housed on the
platforms.
    In 2006, offshore petroleum and natural gas production
CO2 and CH4 emissions accounted for 5.1 million
metric tons CO2e. The primary sources of emissions from
offshore petroleum and natural gas production are from valves, flanges,
open-ended lines, compressor seals, platform vent stacks, and other
source types. Flare stacks account for the majority of combustion
CO2 emissions.
    Offshore petroleum and natural gas production facilities are
proposed for inclusion due to the fact that this segment represents
approximately 1.9 percent of fugitive, vented and incremental \5\
combustion emissions from the petroleum and natural gas industry, an
existing activity data collection system already exists that can
readily be used to calculate GHG emissions (i.e., GOADS) and major
fugitive and vented emissions sources can be characterized by an
existing reasonable methodology which will minimize incremental burden
for reporters. This is consistent with comments received on the initial
proposed rule.
---------------------------------------------------------------------------

    \5\ The denominator includes total fugitive and vented
emissions, as well as any additional combustion related emissions
that will be required to be reported by the petroleum and natural
gas industry and that wasn't already covered in the final MRR.
---------------------------------------------------------------------------

Onshore Natural Gas Processing
    Natural gas processing facilities remove hydrocarbon and water
liquids and various other constituents (e.g., hydrogen sulfide, carbon
dioxide, helium, nitrogen, and hydrocarbons heavier than methane) from
the produced natural gas. The resulting ``pipeline quality'' natural
gas is transported to transmission pipelines. Natural gas processing
facilities also include gathering/boosting stations that dehydrate and
compress natural gas to be sent to natural gas processing facilities or
directly to natural gas transmission or distribution systems.
Compressors are used within gathering/boosting stations to adequately
pressurize the natural gas so that it can be transported to natural gas
processing, transmission, and distribution facilities through gathering
pipelines. In addition, compressors at natural gas processing
facilities are used to boost natural gas pressure so that it can pass
through all of the processes and into the high-pressure transmission
pipelines.
    Vented and fugitive CH4 emissions from reciprocating and
centrifugal compressors, including centrifugal compressor wet and dry
seals, wet seal oil degassing vents, reciprocating compressor rod
packing vents, and all

other compressor emissions, are the primary CH4 emission
sources from this segment. The majority of vented CO2
emissions come from acid gas removal vent stacks, which are designed to
remove CO2 and hydrogen sulfide, when present, from natural
gas. While these are the major emissions sources in natural gas
processing facilities, other potential sources such as dehydrator vent
stacks, piping connectors, open-ended vent and drain lines and
gathering pipelines associated with the processing plant would also
need to be reported under the proposed supplemental rule.
    Onshore natural gas processing facilities are proposed for
inclusion due to the fact that these operations represent a significant
emissions source, approximately 8 percent of fugitive, vented and
incremental \6\ combustion emissions from the natural gas segment,
methods are available to estimate emissions, and there are a reasonable
number of reporters. Most natural gas processing facilities proposed
for inclusion in this supplemental proposed rulemaking would already be
required to report under subpart C and/or subpart NN of the Final MRR.
---------------------------------------------------------------------------

    \6\ The denominator includes total fugitive and vented
emissions, as well as any additional combustion related emissions
that will be required to be reported by the petroleum and natural
gas industry and that wasn't already covered in the final MRR.
---------------------------------------------------------------------------

Onshore Natural Gas Transmission Compression Facilities and Underground
Natural Gas Storage
    Natural gas transmission compression facilities move natural gas
throughout the U.S. natural gas transmission system. Natural gas is
also injected and stored in underground formations during periods of
low demand (e.g., spring or fall) and withdrawn, processed, and
distributed during periods of high demand (e.g., winter or summer).
Storage compressor stations are dedicated to gas injection and
extraction at underground natural gas storage facilities.
    Vented and fugitive CH4 emissions from reciprocating and
centrifugal compressors, including compressor and station blowdowns,
centrifugal compressor wet and dry seals, wet seal oil degassing vents,
reciprocating compressor rod packing vents, unit isolation valves,
blowdown valves, compressor scrubber dump valves, gas pneumatic
continuous bleed devices and all other compressor fugitive emissions,
are the primary CH4 emission source from natural gas
transmission compression stations and underground natural gas storage
facilities. Dehydrators are also a significant source of CH4
emissions from underground natural gas storage facilities. While these
are the major emissions sources in natural gas transmission, other
potential sources include, but are not limited to, condensate (water
and hydrocarbon) tanks, open-ended lines and valve stem seals.
Condensate tank vents in transmission can be a significant source of
emissions from malfunctioning compressor scrubber dump valves and will
require detection of such leakage by an optical imaging instrument and
direct measurement where found present.
    Onshore natural gas transmission compression facilities and
underground natural gas storage facilities are proposed for inclusion
due to the fact that these operations represent significant sources of
fugitive, vented and incremental \7\ combustion emissions, 15 and 2
percent, respectively, methods are available to estimate emissions, and
there are a reasonable number of reporters. Further, this segment was
included in the initial proposed rule and EPA has made improvements to
the proposal based on comments received.
---------------------------------------------------------------------------

    \7\ The denominator includes total fugitive and vented
emissions, as well as any additional combustion related emissions
that will be required to be reported by the petroleum and natural
gas industry and that wasn't already covered in the final MRR.
---------------------------------------------------------------------------

LNG Import and Export and LNG Storage
    The U.S. imports and exports natural gas in the form of LNG, which
is received, stored, and, when needed, re-gasified at LNG import and
export terminals. Import and export include both LNG movements between
U.S. and foreign sources as well as transport between U.S. sources. LNG
storage facilities liquefy and store natural gas from processing plants
and transmission pipelines during periods of low demand (e.g., spring
or fall) and re-gasify for send out during periods of high demand
(e.g., summer and winter)
    Fugitive and vented CH4 and CO2 emissions
from reciprocating and centrifugal compressors, including centrifugal
compressor wet and dry seals, wet seal degassing vents, reciprocating
compressor rod packing vents, and all other compressor fugitive
emissions, are the primary CH4 and CO2 emission
source from LNG storage facilities and LNG import and export
facilities. Process units at these facilities can include vapor
recovery compressors to re-liquefy natural gas tank boil-off (at LNG
storage facilities), re-condensers, vaporization units, tanker
unloading equipment (at LNG import terminals), transportation
pipelines, and/or LNG pumps.
    LNG storage ``facilities'' can be defined as facilities that store
liquefied natural gas in above ground storage tanks. LNG import
terminal can be defined as onshore or offshore facilities that receive
imported LNG via ocean transport, store it in storage tanks, re-gasify
it, and deliver re-gasified natural gas to a natural gas transmission
or distribution system. LNG export terminal (facility) can be defined
as onshore or offshore facilities that receive natural gas, liquefy it,
store it in storage tanks, and send out the LNG via ocean
transportation, including to import facilities in the United States.
EPA is proposing inclusion of these facilities because the National
Inventory has very little data on methane emissions in these segments
which are expected to grow substantially in forward years.
Petroleum and Natural Gas Pipelines
    Natural gas transmission involves high pressure, large diameter
pipelines that transport gas long distances from field production and
natural gas processing facilities to natural gas distribution pipelines
or large volume customers such as power plants or chemical plants.
Crude oil transportation involves pump stations and bulk tank terminals
to move crude oil through pipelines and loading and unloading crude oil
tanks, marine vessels, and railroad tank cars. The majority of vented
and fugitive emissions from the transportation of natural gas occur at
the compressor stations, which are proposed for inclusion in the
supplemental rule and discussed above.
    EPA is not proposing to include reporting of fugitive emissions
from natural gas pipeline segments between compressor stations, or
crude oil pipelines and tank terminals in the supplemental rulemaking
due to the dispersed nature of the fugitive emissions, and the fact
that once fugitives are found, the emissions are generally addressed
quickly. For natural gas gathering pipelines, EPA is proposing that
producers who own or operate gathering lines associated with their
production fields and natural gas processors who own or operate
gathering lines associated with their processing plants should include
those gathering lines in their field or processing plant reported
emissions.
Natural Gas Distribution
    Natural gas distribution facilities are local distribution
companies (LDCs) that

include the above grade (above ground) gas metering and pressure
regulation (M&R) equipment, M&R equipment below grade in vaults, buried
pipelines and customer meters used to transport natural gas primarily
from high pressure transmission pipelines to end users. In the
distribution segment, high-pressure gas from natural gas transmission
pipelines enters a ``city gate'' station, which reduces the pressure
and distributes the gas through primarily underground mains and service
lines to individual end users. Distribution system CH4 and
CO2 emissions result mainly from fugitive emissions from
above ground gate stations (metering and regulating stations), below
grade vaults (regulator stations), and fugitive emissions from buried
pipelines. At gate stations, fugitive and vented CH4
emissions primarily come from valves, open-ended lines, connectors,
pressure safety valves, and natural gas driven pneumatic devices.
CH4 emissions in vaults are entirely fugitive, primarily
from piping connectors to meters and regulators.
    Although emissions from a single vault, gate station or segment of
pipeline in the natural gas distribution segment may not be
significant, collectively these emissions sources contribute a
significant share of emissions from natural gas systems.
    EPA proposes to include natural gas distribution facilities because
these operations represent a significant emissions source,
approximately 6 percent of fugitive, vented and incremental \8\
combustion emissions from the petroleum and natural gas industry. EPA
proposes that LDC's would report for all of the distribution facilities
that they own or operate.
---------------------------------------------------------------------------

    \8\ The denominator includes total fugitive and vented
emissions, as well as any additional combustion related emissions
that will be required to be reported by the petroleum and natural
gas industry and that wasn't already covered in the final MRR.
---------------------------------------------------------------------------

Crude Oil Transportation
    Crude oil is commonly transported by barge, tanker, rail, truck,
and pipeline from production operations and import terminals to
petroleum refineries or export terminals. Typical equipment associated
with these operations is storage tanks and pumping stations. The major
sources of CH4 and CO2 emissions include releases
from tanks and marine vessel loading operations.
    EPA is not proposing to include the crude oil transportation
segment of the petroleum and natural gas industry in this supplemental
rulemaking due to its small contribution to total petroleum and natural
gas CH4 and CO2 emissions, accounting for much
less than 1 percent.

D. Selection of Reporting Threshold

    EPA proposes that owners or operators of facilities with emissions
equal to or greater than 25,000 metric tons CO2e per year be
subject to these reporting requirements. This threshold is applicable
to all petroleum and natural gas system reporters covered by this
subpart: onshore petroleum and natural gas production facilities,
offshore petroleum and natural gas production facilities, onshore
natural gas processing facilities, including gathering/boosting
stations; natural gas transmission compression facilities, underground
natural gas storage facilities; LNG storage facilities; LNG import and
export facilities and natural gas distribution facilities. As described
above, under the proposed rule, for onshore petroleum and natural gas
production facilities an owner or operator (as defined by the proposed
rule) would evaluate emissions from all equipment covered by the
proposed rule, including vented, fugitive, flared and stationary
combustion, in a defined basin against the threshold to determine
applicability.
    Consistent with the rest of the Final MRR, EPA is proposing that
for the purposes of determining whether a facility emits equal to or
greater than a 25,000 mtCO2e, a facility must include
emissions from all source categories for which methods are provided in
the rule. EPA proposes that when a facility determines emissions for
the purposes of the threshold determination under subpart W, that the
fuel combustion emissions estimates include both stationary and
portable equipment (e.g., compressors, drilling rigs, and dehydrators
that are skid-mounted) that are controlled by well operators through
ownership, direct operation, leased and rented equipment, and
contracted operation. Fugitive, vented and combustion emissions from
portable equipment are proposed for inclusion in the threshold
determination for this source category due to the unique nature of the
petroleum and natural gas industry. In addition to well drilling rigs
and their ancillary equipment for well completions, it is common
practice in onshore production to use skid mounted portable
compressors, glycol dehydrators and other equipment partly for
installation cost savings and partly because well flow rates decline
over time and well-head equipment becomes over sized, and is moved
around to match equipment capacity with wells of the same production
capacity.
    Also due to the unique nature of the industry, EPA believes that it
may be possible that onshore petroleum and natural gas production
equipment from onshore petroleum and natural gas production facilities
may be co-located with other manufacturing facilities already covered
under other subparts of the rule (e.g., cement manufacturing facilities
or glass manufacturing facilities). It is not EPA's intent to have
these manufacturing facilities include emissions from onshore petroleum
and natural gas production equipment in their threshold determination.
EPA seeks comment on this approach.
    To identify the most appropriate threshold level for reporting of
emissions, EPA conducted analyses to determine emissions reporting
coverage and facility reporting coverage at four different threshold
levels: 1,000 metric tons CO2e per year, 10,000 metric tons
CO2e per year, 25,000 metric tons CO2e per year,
and 100,000 metric tons CO2e per year. Table W-2 provides
coverage of emissions and number of facilities reporting at each
threshold level for all the industry segments under consideration for
this proposed supplemental rule.

                                 Table W-2--Threshold Analysis for Emissions From the Petroleum and Natural Gas Industry
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                         Total national                                   Total emissions covered    Facilities covered
                                                            emissions                                           by threshold       ---------------------
                        Segment                         ----------------  Total number      Threshold   ---------------------------
                                                          (metric tons    of facilities       level       (metric tons                Number    Percent
                                                         CO2e per year)                                  CO2e per year)   Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
Onshore Petroleum & Gas Production.....................     277,798,737          27,993         100,000     187,175,289         67        466          2
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............          25,000     224,227,559         81      1,232          4
                                                                                ----------------------------------------------------------------

                                                         ..............  ..............          10,000     242,390,849         87      2,413          9
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............           1,000     268,848,529         97     10,604         38
--------------------------------------------------------------------------------------------------------------------------------------------------------
Offshore Petroleum & Gas Production....................      11,261,305           3,235         100,000       3,242,389         29          4          0
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............          25,000       5,119,405         45         58          2
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............          10,000       7,111,563         63        184          6
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............           1,000      10,553,889         94       1192         37
--------------------------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Processing.................................      33,984,015             566         100,000      24,874,783         73        130         23
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............          25,000      31,229,071         92        289         51
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............          10,000      32,982,975         97        396         70
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............           1,000      33,984,015        100        566        100
--------------------------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Transmission Compression...................      64,059,125           1,944         100,000      34,518,927         54        433         22
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............          25,000      57,683,144         90      1,145         59
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............          10,000      62,672,905         98      1,443         74
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............           1,000      64,051,661        100      1,695         87
--------------------------------------------------------------------------------------------------------------------------------------------------------
Underground Natural Gas Storage........................       9,713,029             397         100,000       3,548,988         37         36          9
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............          25,000       7,846,609         81        133         34
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............          10,000       8,968,994         92        200         50
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............           1,000       9,696,532        100        347         87
--------------------------------------------------------------------------------------------------------------------------------------------------------
LNG Storage............................................       2,113,601             157         100,000         695,459         33          4          3
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............          25,000       1,900,793         90         33         21
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............          10,000       2,030,842         96         41         26
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............           1,000       2,096,974         99         54         34
--------------------------------------------------------------------------------------------------------------------------------------------------------
LNG Import and Export \2\..............................         315,888               5         100,000         314,803       99.7          4         80
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............          25,000         314,803       99.7          4         80
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............          10,000         314,803       99.7          4         80
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............           1,000         315,888     100.00          5        100
--------------------------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Distribution...............................      25,258,347           1,427         100,000      18,470,457         73         66          5
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............          25,000      22,741,042         90        143         10
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............          10,000      23,733,488         94        203         14
                                                                                ----------------------------------------------------------------
                                                         ..............  ..............           1,000      24,983,115         99        594        42
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\The emissions include fugitive and vented CH4 and CO2 and combusted CO2, N2O, and CH4 gases. The emissions for each industry segment do not match the
  2008 U.S. Inventory either because of added details in the estimation methodology or use of a different methodology than the U.S. Inventory. For
  additional discussion, refer to Greenhouse Gas Emissions from the Petroleum and Natural Gas Industry: Background TSD (EPA-HQ-OAR-2009-0923).
\2\ The analysis included only import facilities. There is only one export facility, located in Kenai, Alaska.

    EPA is proposing a threshold of 25,000 metric tons CO2e
applied to those emissions sources listed in Table W-2, which will
cover approximately 83 percent of estimated vented and fugitive
emissions and incremental combustion emissions from facilities that did
not meet the reporting requirements under Subpart C alone, from the
entire petroleum and natural gas industry, while requiring only a small
fraction of total facilities to report. For additional information,
please refer to Greenhouse Gas Emissions from the Petroleum and Natural
Gas Industry: Background TSD (EPA-HQ-OAR-2009-0923). For specific
information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the Economic Impact
Analysis.
    Although EPA is proposing an emissions threshold of 25,000
mtCO2e for all segments of the petroleum and natural gas
industry, EPA is taking comment on whether a 10,000 mtCO2e
threshold for onshore petroleum and natural gas production would be
more appropriate.
    For onshore petroleum and natural gas production, EPA is proposing
that portable and stationary fuel combustion emissions be included in
the threshold determination due to the large percentage of emissions
from portable equipment in the petroleum and natural gas industry. EPA
considered lowering the threshold to 10,000 mtCO2e and
excluding portable equipment from the threshold determination (and
reporting), however, data were not available to distinguish portable
and stationary combustion emissions in order to evaluate the lower
threshold considering just stationary combustion emissions.
    Secondly, for onshore petroleum and natural gas production, EPA is
proposing that owners or operators report at the basin level. EPA is
seeking comment on owners or operators reporting at the field level.
Although EPA believes that a 25,000 mtCO2e threshold is
appropriate for the basin level approach, as described above, EPA seeks
comment on whether the threshold should be lowered to 10,000
mtCO2e if reporting were to be at the field level. Table W-3
presents the emissions and facility coverage for a field level
definition for onshore petroleum and natural gas production.

            Table W-3--Emissions Coverage and Entities Reporting for Field Level Facility Definition
----------------------------------------------------------------------------------------------------------------
                                                         Emissions covered              Facilities covered
                                                 ---------------------------------------------------------------
               Threshold level \2\                  Metric tons
                                                     CO2e/year        Percent         Number          Percent
----------------------------------------------------------------------------------------------------------------
100,000.........................................      99,776,033              38             305               0
25,000..........................................     144,547,282              55           1,253               2
10,000..........................................     169,160,462              64           2,846               3
1,000...........................................     242,621,431              92          39,652              48
----------------------------------------------------------------------------------------------------------------

    In addition to seeking comment on the proposed threshold for
onshore production, EPA more broadly is seeking comment on the
selection of the threshold for all segments of the petroleum and
natural gas industry.

E. Selection of Proposed Monitoring Methods

    Many domestic and international GHG monitoring guidelines and
protocols include methodologies for estimating emissions from petroleum
and natural gas operations, including the 2006 IPCC Guidelines, U.S.
GHG Inventory, DOE 1605(b), and corporate industry protocols developed
by the American Petroleum Institute, the Interstate Natural Gas
Association of America, and the American Gas Association. The
methodologies proposed vary by the emissions source and the level of
accuracy desired in the estimation.
    EPA has carefully considered possible options to estimate emissions
from every emission source proposed for reporting. EPA has proposed to
use the most appropriate method taking into account both the cost to
the reporter as well as accuracy of emissions achieved through the
proposed method. Overall, we propose the following types of monitoring
methods: (1) Direct measurement to develop site and source-specific
emission factors; (2) engineering estimation; (3) combination of direct
measurement and engineering estimation; (4) leak detection and use of
leaker emission factor; and (5) population count and population
emission factors. Table W-4 of this preamble provides a list of the
emissions sources to be reported with the corresponding monitoring
methods.
    A monitoring method proposed for a specific source is to be used
across all reporting segments of the petroleum and gas system. Two
exceptions to this are: (1) For tanks in onshore natural gas
transmission facilities that exhibit gas bypass from scrubber dump
valves, EPA is proposing to require direct measurement under the
proposal, whereas in other segments under the proposal, the emissions
from tanks would be required to be estimated using E&P Tank simulation
software; and (2) under the proposal, fugitive emissions from onshore
petroleum and natural gas production and inaccessible to plain view
(buried or below grade in vaults) emissions in gas distribution would
require estimation using population emissions factors as opposed to
other segments' fugitive emissions that require leak detection and the
use of leaker emissions factors. Finally, offshore petroleum and
natural gas production platforms would be required under the proposal
to use methods provided by the most recent GOADS reporting system. This
means that Federal Gulf of Mexico platforms would report emissions
already being calculated and reported to MMS as a part of the GOADS
study and the remaining platforms that are not a part of the GOADS
study (i.e., platforms in all state waters and other Federal waters
outside the Gulf of Mexico) would be required to adopt the GOADS
methodology.

       Table W-4. Source Specific Monitoring Methods and Emissions
                             Quantification
------------------------------------------------------------------------
                                                           Emissions
         Emission source          Monitoring methods    quantification
                                                            methods
------------------------------------------------------------------------
Natural Gas Pneumatic Bleed       Engineering         Manufacturer
 Devices (High or Continuous).     Estimation.         device model
                                                       bleed rate and
                                                       engineering
                                                       calculation.

Natural Gas Pneumatic Bleed       Component Count...  Population
 Devices (Low).                                        emissions factor.
Natural Gas Driven Pneumatic      Engineering         Manufacturer model
 Pump Venting.                     Estimation.         emissions per
                                                       unit volume and
                                                       volume pumped.
Acid Gas Removal Vent Stacks      Engineering         Engineering
 (CO2 only).                       Estimation.         Calculation and
                                                       flow meters.
Dehydrator Vent Stacks..........  Engineering         GlyCalc simulation
                                   Estimation.         software.
Well Venting for Liquids          (1) Engineering     (1) Field specific
 Unloading.                        Estimation or (2)   emission factor
                                   Direct              times events or
                                   Measurement.        (2) Flow metered
                                                       emission factor
                                                       times events.
Gas Well Venting during           (1) Engineering     (1) Field specific
 Completions or Workovers.         Estimation, or      emission factor
                                   (2) Direct          times events or
                                   Measurement.        (2) Flow metered
                                                       emission factor
                                                       times events.
Blowdown Vent Stacks............  Engineering         Equipment specific
                                   Estimation.         emission factor
                                                       and number of
                                                       events.
Storage Tanks (Onshore            Engineering         E&P Tank equipment
 Production and Processing).       Estimation.         specific emission
                                                       factor times
                                                       throughput.
Storage Tanks (Transmission)....  Direct Measurement  Flow metered
                                                       emission factor
                                                       time operating
                                                       hours.
Well Testing Venting and Flaring  Engineering         Gas to oil Ratio
                                   Estimation.         (GOR); flow rate.
Associated Gas Venting and        Engineering         Gas to oil Ratio
 Flaring.                          Estimation.         (GOR); flow rate.
Flare Stacks....................  (1) Direct          Engineering
                                   Measurement or      Calculation.
                                   (2) Engineering
                                   Estimation.
Centrifugal Compressor Wet Seal   Direct Measurement  Flow metered
 Oil Degassing Vent.                                   equipment
                                                       specific emission
                                                       factor times
                                                       operating hours.
Large Reciprocating Compressor    Direct Measurement  Flow metered
 Rod Packing Vents.                                    equipment
                                                       specific emission
                                                       factor times
                                                       operating hours.
Large Compressor Blowdown Valve   Leak Detection      Flow metered
 Leak.                             with optical gas    equipment
                                   imaging             specific emission
                                   instrument.         factor times
                                                       operating hours.
Large Compressor Blowdown Vent    Leak Detection      Flow metered
 (Unit Isolation Valve Leak).      with optical gas    equipment
                                   imaging             specific emission
                                   instrument.         factor times
                                                       stand-by
                                                       depressurized
                                                       hours.
Fugitive Sources (Processing,     Leak Detection      Leaker emission
 Transmission, Underground         with optical gas    factors times
 Storage, LNG Storage, LNG         imaging             detected leaks.
 Import Export, LDC).              instrument.
Fugitive Sources (Onshore         Component Count...  Population
 Production, LDC).                                     Emission Factors
                                                       times components.
------------------------------------------------------------------------

1. Direct Measurement
    EPA is proposing to require five sources in this supplemental
proposal to directly measure emissions: storage tanks (transmission)
when scrubber dump valves are detected leaking, centrifugal compressor
wet seal oil degassing vents, large reciprocating compressor rod
packing vents, large compressor blowdown vent valve leaks, and large
compressor blowdown vent (unit isolation valve leaks), the latter two
when leakage is detected. For example, storage tanks in the onshore
natural gas transmission segment typically store the condensate (water,
light hydrocarbons, seal oil) from the scrubbing of pipeline quality
gas. The volume and composition of liquid is typically low and
variable, respectively, in comparison to the volumes and composition of
hydrocarbon liquids stored in the upstream segments of the industry.
Hence the emissions from condensate itself in the transmission segment
are considered insignificant. However, scrubber dump valves malfunction
or stick-open due to debris in the condensate and can remain open
resulting in natural gas bypass via the open dump valve to and through
the condensate tank, and therefore the use of E&P Tanks and other
models are not applicable to tanks in the transmission segment. The
only potential option for measuring emissions from scrubber dump valves
is to monitor storage tank emissions with a gas imaging camera to
determine if the emissions do not subside and become negligible when
dump valves close. If the scrubber dump valve is stuck and leaking
natural gas through the tank then the emissions will be visibly
significant and will not subside to inconspicuous volumes. If the
scrubber dump valve functions normally and shuts completely after the
condensate has been dumped then the storage tank, emissions should
subside and taper off to insignificant quantities. If emissions are
detected to be continuous for a duration of five minutes then a one-
time measurement would be required using a temporary meter to establish
an equipment specific emission factor.
    This proposal is based on the fact that the emissions magnitude
from these five sources are significant enough to warrant reporting for
the supplemental proposed rule and that no credible engineering
estimation methods or emissions factors exist that can accurately
characterize the emissions. There are several public reference studies
and guidance documents that provide emissions factors for these
sources. However, after close review, EPA has determined that these
emissions factors cannot uniquely characterize the emissions
specifically from individual equipment or a facility. For example, the
emissions from wet seal degassing and rod packing are directly
correlated to the size of the compressor, throughput, and the operating
time of the compressor in the reporting year. Also, in the case of unit
isolation valves and compressor blow down valves the emissions
magnitude varies depending on operational and maintenance practices as
valves can have excessive leakage, especially when a compressor is not
in operation. These factors do not get accounted for using an emissions
factor.
    The proposed supplemental rule would require that rod packing and
blowdown valves be measured for emissions both in operating as well as
standby pressurized modes. In addition, unit isolation valve leaks
would be required to be measured at the

blowdown vent in the standby de-pressurized mode. To correctly quantify
emissions from centrifugal and large reciprocating compressors the
proposal would require that, for each compressor, one measurement be
taken in each of the operational modes that occurs during a reporting
period: (i) Operating, (ii) standby pressurized, and (iii) not
operating, depressurized. Depending on the operational practices each
mode could have significantly different emissions and would need to be
separately quantified as a part of the proposed rule.
    For direct measurement, EPA proposes that the following
technologies be used: high volume samplers, meters (such as rotameters,
turbine meters, hot wire anemometers, and others), and/or calibrated
bags. EPA recognizes that different measurement equipment would be
required for different source emissions measurement depending on the
configuration of the system. Hence the proposed rule provides these
options for multiple direct measurement equipment, but the reporter
must calibrate and maintain the equipment based on either consensus
based standards or an appropriate method specified by the equipment
manufacturer, as specified in the proposed rule. Where a vent emission
source cannot be accessed on the ground or from a fixed platform, the
reporter has the choice of using a man-lift or installing either a
permanent or temporary vent line access port through which a meter can
be inserted to measure flow or velocity. If emissions exceed the
maximum range of one measurement instrument, the reporter would be
required to use a different instrument option that can measure larger
magnitude emissions levels. For example, if a high volume sampler
maximum rate is exceeded by an emissions source, then emissions would
be required to be directly measured using either calibrated bagging or
a meter. CH4 and CO2 emissions from the emissions
stream would be required to be calculated using the composition of the
gas in the process equipment (compressor).
2. Engineering Estimation
    This proposed rule would require two main types of engineering
calculation methods for emissions; (1) volumetric calculation method,
and (2) engineering first principle methods.
(1) Volumetric Calculation Method
    The volumetric calculation method has been proposed for calculating
CH4 and CO2 vent emissions from sources where the
variable in the emissions magnitude on an annual basis is the number of
times the source releases CH4 and CO2 emissions
to the atmosphere. In addition, the estimation of the total volume of
emissions is a matter of simple arithmetic calculation without the need
for complex calculations. For example, when a compressor is taken
offline for maintenance, the volume of CH4 and
CO2 blowdown vent emissions that are released is the same
during each release, is easily calculable, and the only variable is the
number of times the compressor is taken offline and vented.
(2) Engineering First Principle Methods
    Emissions from sources such as tanks and glycol dehydrators can be
reliably calculated using standard engineering first principle methods
such as those available in E&P Tank and GlyCalc. The use of such
standard and readily available software is a cost-effective way to
uniformly estimate emissions that are representative for the two
sources. To maintain standardization across reporters the proposed rule
would require the use of E&P Tank for estimating the emissions from
well-pad separator conditions when flashed to atmospheric pressure in
any downstream stock tank, and GlyCalc for glycol dehydrators.
    E&P Tank is available for free and GlyCalc can be purchased at a
small fee. Also, these two software models are widely used in the
industry and the operation of the software is well understood. Using
such software also addresses safety concerns that are associated with
direct measurement from the two sources. For example, sometimes the
temperature of the emissions stream for glycol dehydrator vent stacks
is too high for operators to safely measure emissions. EPA seeks
comment on whether there are additional or alternative software
packages to E&P Tank and GlyCalc that should be required to be used to
calculate emissions.
    In cases where tank emissions do not represent equilibrium
conditions of the liquid in a gas-liquid separator and no publicly
available data are available on vapor bypass direct measurement would
be required under the proposal. For pressurized liquids sent to
atmospheric storage tanks where tank emissions are not expected to be
represented by the equilibrium conditions of the liquid in a gas-liquid
separator as calculated by the E&P Tank Model, then emissions
calculated by E&P Tank would be multiplied by an empirical factor.
    The supplemental proposed rulemaking does not include emissions
from tanks containing primarily water with the exception of
transmission station condensate tanks where dump valve are determined
to be bypassing gas. Therefore, EPA seeks comments on how to quantify
emissions from tanks storing water without resulting in additional
reporting burden to the facilities.
    For further discussion of these software programs and emissions
calculation methods, refer to Greenhouse Gas Emissions from the
Petroleum and Natural Gas Industry: Background TSD (EPA-HQ-OAR-2009-
0923).
3. Combination of Direct Measurement and Engineering Estimation
    Several sources provide a choice between engineering estimation
based on operating data and direct measurement (if meters are already
installed). For continuous flaring, a one-time direct measurement or
engineering estimate may be performed in conjunction with engineering
estimation based on operating data that relates to the quantity of
flared gas. For well completion venting and well workover venting (each
during flowback after hydraulic fracturing, the only significant well
completion emissions), EPA explored the possibility of using a meter
for measuring hydrocarbon gas lost during these venting events which
may last from one to ten days. Some companies have reported directly
measuring these emissions under certain circumstances. However, such
metering could be technically challenging, if not impossible, and also
burdensome given the number of well completions and workovers being
conducted on an annual basis.
    It is important to note, however, that no body of data has been
identified that can be summarized into generally applicable emissions
factors to characterize emissions from these sources in each unique
field. In fact, the emissions factor being used in the 2008 U.S. GHG
Inventory is believed to significantly underestimate emissions based on
industry experience as included in the Natural Gas STAR Program
publicly available information (http://www.epa.gov/gasstar/). In
addition, the 2008 U.S. GHG Inventory emissions factor was developed
prior to the boom in unconventional well drilling (1992) and in the
absence of any field data and does not capture the diversity of well
completion and workover operations or the variance in emissions that
can be expected from different hydrocarbon reservoirs in the country.
    As a result, EPA proposes the development of a field-specific
emission factor either by direct measurement of

flow rate of hydrocarbons using a meter or by an engineering estimation
based on well choke pressure drop. Given the large number of well
completions and well workovers, EPA proposes that one representative
well completion and one well workover per field horizon be developed to
characterize emissions per day of venting from all other completions
and workovers in that field horizon. The reporter would be required to
update this factor every two years. This would alleviate burden but at
the same time achieve a reasonable characterization of the emissions
from these two sources.
5. Use of Leak Detection and Leaking Component Emission Factors
    Each segment of the petroleum and gas system has a variety of
fugitive emissions sources that at a source type level have low
emissions volume, but combined together at a segment level contribute
significantly towards the total emissions from petroleum and gas
systems. EPA considered several options for estimating emissions from
fugitive emissions sources. One option considered was to use a
population count of each fugitive emissions source (e.g., source types
such as valves, connectors, etc.) and multiply it by a population
emissions factor. This option would not account for differences in
operational and maintenance practices among facilities. If population
emissions factors are used then the fugitive emissions from a
particular facility will remain constant indefinitely until the
facilities are modified (i.e., change the population of equipment) or
new factors are provided. This approach also will not account for
fugitive emissions reduction measures the industry has undertaken in
the last few years since the population emission factors were
developed. Facilities with good maintenance practices may have fugitive
emissions lower than the population emission factors. As described
further below, EPA requests comment on the use of emission factors and
ways in which these shortcomings may be overcome.
    Another option considered was the use of fugitive emissions
detection (e.g., an infrared camera) and direct measurement (e.g.,
calibrated bags or high volume samplers) for fugitive sources. This
option may be more cost-effective when the sources of fugitive
emissions are in a relatively small geographic area such as at a
processing plant, gas compressor station, or distribution gate station.
This approach, however, could be less cost effective for widely
dispersed sources (e.g., well pads and gathering lines).
    Hence, to overcome these issues, EPA proposes conducting fugitive
emissions detection and then applying leaking component (or leak only)
emissions factors for processing, transmission, underground storage,
LNG storage, LNG import and export terminals, and LDC gate stations.
The fugitive emissions leak detection method does not require
corresponding direct measurement of the fugitive emissions, which is
significantly more burdensome than fugitive emissions detection using
the most modern optical gas imaging instrument detection technology.
This method is an improvement over the use of population emissions
factors because the factors were developed for leaking components and
applied only to leaking components, leading to a more accurate
calculation of emissions from each piece of equipment. Several
commenters to the initial proposed rule recommended leak detection with
an optical gas imaging instrument and quantification with emission
factors. In addition, leaking component emissions factors are applied
only to those emissions sources that are determined to be emitting as a
result of the fugitive emissions detection process.
    EPA analyzed new fugitive leak studies specifically performed on
natural gas facilities in processing plants and transmission compressor
stations, as recommended by several Subpart W initial proposed rule
commenters. Leaking component emissions factors from these studies were
compared with other studies (see below). EPA found that emission
factors generated from the Clearstone studies related better to
methane-rich stream fugitives and were more appropriate than other
emission factors developed for highly regulated refinery and
petrochemical plants on VOC emissions. Therefore, EPA is using
emissions data from the Clearstone studies as the basis for the leaker
factors proposed in this rule. EPA requests comments on the use of
emission factors from the Clearstone studies. For further details see
Greenhouse Gas Emissions from the Petroleum and Natural Gas Industry:
Background TSD (EPA-HQ-OAR-2009-0923).
Emission References for Petroleum and Natural Gas Systems
    API. Compendium of Greenhouse Gas Emissions Methodologies for the
Oil and Gas Industry. American Petroleum Institute. Table 4-7, page 4-
30. February 2004.
    API. Emission Factors for Oil and Gas Production Operations. Table
8, page 10. API Publication Number 4615. January 1995.
    EPA. Identification and Evaluation of Opportunities to Reduce
Methane Losses at Four Gas Processing Plants. Clearstone Engineering
Ltd. June 20, 2002. http://www.epa.gov/gasstar/documents/four_
plants.pdf.
    EPA. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-
2007. Annexes. Tables A-112-A-125. U.S. EPA. April 2009. http://
epa.gov/climatechange/emissions/downloads09/Annexes.pdf.
    EPA. Lessons Learned: Replacing Wet Seals with Dry Seals in
Centrifugal Compressors. U.S. EPA 2006. http://www.epa.gov/gasstar/
documents/ll_wetseals.pdf.
    EPA. Protocol for Equipment Leak Emission Estimates. Emission
Standards Division. U.S. EPA. SOCMI Table 2-7. November 1995. http://
www.epa.gov/ttn/chief/efdocs/equiplks.pdf.
    GRI. Methane Emissions from the Natural Gas Industry. Volume 6.
Table 4-2 and Appendix A, page A-2. June 1996. http://www.epa.gov/
gasstar/documents/emissions_report/6_vented.pdf.
    GRI. Methane Emissions from the Natural Gas Industry. Volume 8.
Tables 4-3, 4-6 and 4-24. June 1996. http://www.epa.gov/gasstar/
documents/emissions_report/8_equipmentleaks.pdf.
    GRI. Methane Emissions from the Natural Gas Industry. Volume 9.
Tables 8-9 and 9-4. June 1996. http://www.epa.gov/gasstar/documents/
emissions_report/9_underground.pdf.
    GRI. Methane Emissions from the Natural Gas Industry. Volume 10.
Table 7-1. June 1996. http://epa.gov/gasstar/documents/emissions_
report/10_metering.pdf.
    ICF. Estimates of Methane Emissions from the U.S. Oil Industry.
Draft. Page 13. October 1999.
    Clearstone. Handbook for Estimating Methane Emissions from Canadian
Natural Gas Systems. Clearstone Engineering Ltd., Enerco Engineering
Ltd., and Radian International. Pages 61-63. May 25, 1998.
    National Gas Machinery Laboratory, Kansas State University;
Clearstone Engineering, Ltd.; Innovative Environmental Solutions, Inc.
Cost-Effective Directed Inspection and Maintenance Control
Opportunities at Five Gas Processing Plants and Upstream Gathering
Compressor Stations and Well Sites. For EPA Natural Gas STAR Program.
March 2006.
    Clearstone. Handbook for Estimating Methane Emissions from Canadian
Natural Gas Systems. Clearstone Engineering Ltd., Enerco Engineering
Ltd, and Radian International. 2007.

    EPA considered the use of the three major types of emissions
detection equipment: optical gas imaging instruments, IR laser detector
instruments and Toxic Vapor Analyzers (TVA) or Organic Vapor Analyzers
(OVA). Optical gas imaging instruments are able to scan hundreds of
source types quickly, allowing for the most efficient survey of
emissions at a broad range of facilities. In addition, EPA recently
adopted detailed performance standards for the optical gas imaging
camera in the Alternative work practice for monitoring equipment leaks
(AWP) (40 CFR part 60 subpart A Sec.  60.18(i)(1) and (2)). We
recognize that the purchase of optical gas imaging instruments can be
costly, especially for smaller facilities. However, EPA believes that
most facilities will opt for contractors to conduct emissions detection
once per year. As mentioned above, several commenters to the initial
proposed rule recommended leak detection with an optical gas imaging
instrument in accordance with the EPA AWP. Hence, the supplemental
proposed rule requires the use of an optical gas imaging instrument
compliant with the operational requirements of the EPA AWP. In contrast
to the EPA AWP, however, the proposed rule does not require multiple
surveys per year and does not require leak repair. As discussed further
below, for this proposed rule, EPA requires comprehensive annual leak
detection of the fugitive emissions sources specified in the proposed
rule. The proposed supplemental rule does not allow for the use of an
OVA/TVA. The OVA/TVA requires the operator to physically access the
emissions source with the probe and thus is much more time intensive
than using the optical gas imaging instrument. In addition, the OVA/TVA
range is limited to the reach of an operator standing on the ground or
fixed platform, thus excluding all emissions out of reach. However, EPA
is seeking comments on allowing the OVA/TVA to be used as another
option to the optical imaging camera in this proposed rule.
    EPA is aware that the optical gas imaging instrument's ``detection
sensitivity levels'' as required by the AWP were established from data
on volatile organic compound (VOC) emissions from petroleum refineries
and chemical plants. The optical gas imaging instrument has been used
extensively to successfully detect methane emissions in the petroleum
and gas industry by petroleum and gas companies. A 2006 independent
study funded through a grant by EPA and conducted by Clearstone
Engineering, was an extensive study of methane emissions in gas
processing plants and upstream gathering compressor stations and well
sites. Method 21 was employed to detect leaks and HiFlow samplers were
used to determine the emissions from those leaks. This study surveyed
approximately 74,000 components finding 3,650 leaks (4.9 percent). Of
these leaks, 497 (<1 percent of total components) contributed 90
percent of the total fugitive emissions. The smallest of the 497 leaks
was 177 grams per hour, so an optical gas imaging instrument should be
able to adequately image methane leaks since the smallest leak was well
above the 60 to 100 gram per hour detection sensitivity in Table 1 of
the AWP. Therefore, for the purposes of this reporting rule, EPA
determined that an optical gas imaging instrument that meets the
detection sensitivity requirements of the AWP for any monitoring
frequency as specified in Table 1 of the AWP, is acceptable for use
under this proposed rule. Leak detection and leaker emission factors
only apply to emissions sources in streams with gas content greater
than 10 percent CH4 plus CO2 by weight. Emissions
sources in streams with gas content less than 10 percent CH4
plus CO2 by weight do not need to be reported.
    The proposed rule requires that the survey for fugitive emissions
detection be comprehensive. This means that, on an annual basis, the
entire population of fugitive emissions sources proposed for reporting
in this rule would be surveyed at least once. EPA proposes that
emissions are quantified using leaker emissions factors. Under the
proposal, if a component fugitive emission is detected, emissions are
assumed to occur the entire 365 days in the year.
    EPA is aware that the petroleum and natural gas industry is already
implementing voluntary fugitive emissions detection and repair
programs. Such voluntary programs are useful, but pose an accounting
challenge with respect to emissions reporting for this proposed rule.
The proposed approach does not preclude any owner or operator from
detecting and repairing fugitive emissions prior to quantifying
emissions for the purposes of reporting under this proposed rule.
    To address this issue, EPA considered, but did not propose,
requiring a facility to conduct multiple surveys and to report
emissions using the appropriate leaker factors. Under this approach, if
a specific emission source is found not leaking in the initial survey
but leaking in subsequent surveys, emissions would be quantified from
the date of the first survey where a leak was detected forward through
the time when the leak is fixed, or the end of the year, whichever is
first. Similarly, if an emissions source is found to be leaking in the
initial survey, emissions would be quantified from the date of that
survey through to when the leak is repaired, or the end of the year,
whichever is first. Under this approach, emissions would reflect leak
reductions as determined by repairs and follow-up detection surveys
    EPA seeks comment on whether this alternative approach better
estimates annual facility emissions without resulting in additional
reporting burden to the facilities. Further, we seek comment on
whether, if implemented, multiple surveys should be optional or
required for owners or operators.
6. Use of Population Count and Population Emission Factor
    Fugitive emissions detection and use of leaking component emissions
factors are not always cost effective and can be burdensome. This is
particularly true of onshore petroleum and natural gas production where
the fugitive sources are spread out across large geographical areas and
fugitive emissions are a minor contributor to total segment emissions.
In the distribution segment, pipeline fugitive emissions are a large
fraction of total emissions, but the pipelines are buried where leaks
are difficult to detect. Similarly, metering/regulator stations, which
are an important source of fugitive emissions, are sometimes located
inside underground vaults that are difficult to access. In such
scenarios, fugitive emissions detection can be burdensome. Therefore,
for onshore petroleum and natural gas production, gas gathering
pipelines and LDC pipelines and M&R stations below grade in vaults, the
proposed rule requires the use of population count of emissions sources
and population emissions factor to estimate fugitive emissions.
Population count and population emission factors only apply to
emissions sources in streams with gas content greater than 10 percent
CH4 plus CO2 by weight. Emissions sources in
streams with gas content less than 10 percent CH4 plus
CO2 by weight do not need to be reported. EPA is using
emissions data from studies listed in the Emission References
(2, 4, 5, 7, 8, 9
above) as the basis for the population emissions factors proposed in
this rule. However, the API compendium emissions factors that we are
proposing to use in the upstream oil and gas production sector may be
underestimating emissions. EPA seeks comment on how to improve these

factors and/or collect more accurate data.
7. Alternative Monitoring Methods Considered
    Before selecting the monitoring methods proposed above, we
considered additional measurement methods. The use of Method 21 was
considered for fugitive emissions detection and measurement. Although
Toxic Vapor Analyzers (TVA) and Organic Vapor Analyzers (OVA) were
considered they were not proposed for fugitive emissions detection and
quantification.
    Method 21. This is the reference method for equipment leak
detection and repair regulations for volatile organic compound (VOC)
and hazardous air pollutant (HAP) emissions under several 40 CFR part
60, 40 CFR part 61, 40 CFR part 63, and 40 CFR part 65 emission
standards. Petroleum refineries, chemical plants and large gas
processing plants are required under state and federal laws to perform
LDAR (Leak Detection and Repair) to control VOC air pollution
emissions. LDAR programs require VOC and/or HAP leak detection using
instruments specified in Method 21, and requires repair of leaks if the
rate is above the leak definitions specified within the specific
regulation (typically between 500 parts per million to 10,000 parts per
million as read on an OVA). Some states and air quality districts have
lower leak definitions than the Federal standards. LDAR programs
require facilities to conduct multiple surveys per year: either
following equipment-specific frequencies using VOC monitoring
instruments, or bi-monthly, semi-quarterly or monthly using an optical
gas imaging instrument, frequency depending on the sensitivity
detection of the instrument. While LDAR programs do not require
quantification, state inventories of air emissions use this LDAR leak
detection data with ``leaker'' factors developed by the Synthetic
Organic Chemicals Manufacturing Industry (SOCMI) to estimate the
quantity of VOC emissions. These factors were developed from petroleum
refinery and petrochemical plant data using Method 21. SOCMI factors
adjusted for methane content are considerably lower than the methane
factors proposed in this rule, which were developed from more recent
studies of gas processing plants and compressor stations.
    The Federal LDAR program recently adopted an alternative work
practice that allows use of optical gas imaging instruments in place of
the VOC monitoring instrument specified in Method 21. In a similar
vein, this rule proposes the use of optical gas imaging instruments to
detect leaks once per year, and has developed leaker factors specific
to methane from several recent studies quantifying component leaks in
petroleum and gas facilities. While this rule proposes a similar
approach to Method 21, given that this is a reporting rule for
collecting annual GHG emissions, there are several key differences: the
proposed annual reporting rule is focused on gathering fugitive and
vented CO2 and CH4 emissions, does not require
multiple surveys per year, and does not allow measurement using an OVA/
TVA for the reasons cited above. Optical gas imaging instruments were
found to be more appropriate for leak detection for the proposed
supplemental rule as these instruments are able to scan hundreds of
source components quickly, including components out of reach for an
OVA/TVA.
    Mass Balance for Quantification. Except in one case, EPA
considered, but decided not to propose, the use of a mass balance
approach for quantifying emissions across an entire facility. This
approach would take into account the volume of gas entering a facility
and the amount exiting the facility, with the difference assumed to be
emitted to the atmosphere. This is most often discussed for emissions
estimation from the transportation segment of the industry. However,
for pipeline transportation, the mass balance is often not recommended
because of the uncertainties surrounding meter readings, the highly
variable line pack of high pressure gas and the large volumes of
throughput relative to emissions.
    EPA is proposing this approach in the case of one emission source--
acid gas recovery units. Typically, the natural gas volumes and
compositions are measured both at the inlet and outlet of the acid gas
recovery units as it is required to ensure that natural gas meets
transmission system pipeline specifications. Hence, it is considered
sufficiently feasible to use the mass balance approach for this source.
For all other facilities and sources, the accuracy required in volume
measurements will be a significant added burden in addition to being
unreliable in many cases.

F. Selection of Procedures for Estimating Missing Data

    The proposal requires data collection for a single source a minimum