[Federal Register Volume 75, Number 69 (Monday, April 12, 2010)]
[Proposed Rules]
[Pages 18608-18650]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-6767]



[[Page 18607]]

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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

  Federal Register / Vol. 75 , No. 69 / Monday, April 12, 2010 / 
Proposed Rules  

[[Page 18608]]


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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: [email protected]. Include EPA-HQ-OAR-2009-0923 and/or RIN number 2060-AP99 
in the subject line of the message.
     Fax: (202) 566-1741.
     Phone: (202) 566-1744.
     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: (202) 343-9263; fax number: (202) 343-2342; e-mail 
address: [email protected]. For technical information contact the 
Greenhouse Gas Reporting Rule Hotline at telephone number: (877) 444-
1188; or e-mail: [email protected]. 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 202-343-9263.

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 (202) 343-9263, e-mail: 
[email protected].
    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

[[Page 18609]]

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

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    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

[[Page 18611]]

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

[[Page 18612]]

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

[[Page 18613]]

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

[[Page 18614]]

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

[[Page 18615]]

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

[[Page 18616]]

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

[[Page 18617]]

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
                                                                                        ----------------------------------------------------------------

[[Page 18618]]

 
                                                         ..............  ..............          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.


[[Page 18619]]

    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.

[[Page 18620]]

 
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

[[Page 18621]]

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

[[Page 18622]]

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.

[[Page 18623]]

    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

[[Page 18624]]

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 
of once a year. If data are lost or an error occurs during emissions 
detection and/or measurement or calculation, the operator would be 
required to carry out the detection, direct measurement, and/or 
calculation a second time to obtain the relevant data point(s) as soon 
as the missing data are discovered. If this falls outside of the 
reporting year (e.g. between the end of the reporting year and the date 
when the emissions must be reported) the operator would be required to 
perform the necessary data development and report the results for the 
previous year. This prior year's lost data replacement could not be 
used as the one-time data collection for the current year. Where 
missing data procedures are used for the previous year, at least 30 
days would be required to separate emissions estimation and/or 
measurements for the previous year and emissions estimation and/or 
measurements for the current year of data collection in order to better 
represent emissions estimates for different years. Similarly, 
engineering estimates would account for relevant source counts and 
frequency from the previous reporting period.

G. Selection of Data Reporting Requirements

    EPA proposes that emissions from the petroleum and natural gas 
industry be reported on an annual basis. The reporting should be by the 
owner or operator of the facility as defined in the supplemental rule. 
Emissions from each source type at the facility would be required to be 
aggregated for reporting, with a few exceptions for field level 
reporting (e.g., well completions and well workovers). For other 
equipment, unit-level reporting would not be required. For example, the 
owner or operator with multiple reciprocating compressors in an onshore 
production basin would be required to report emissions collectively 
from all rod packings on all cylinders from all compressors for all 
fields in that basin as specified in this proposed rulemaking. 
Generally, EPA has proposed that onshore production be reported at the 
basin level, as opposed to the unit or field level, to minimize 
reporting burden. EPA notes that in a concurrent proposed rulemaking 
for facilities that conduct CO2 injection or geologic 
sequestration (subpart RR), the term ``facility'' is defined at a more 
disaggregated level, specifically as a ``well or group of wells.'' EPA 
seeks comment on the use of more disaggregated reporting options for 
subpart W.
    Emissions from all sources proposed for monitoring, whether in 
operating condition or on standby, would have to be reported. Any 
emissions resulting from standby compressor sources would

[[Page 18625]]

be separately identified from the aggregate emissions.
    The owner or operator would be required to report the following 
information to EPA as a part of the annual emissions reporting: 
fugitive, vented and flare combustion emissions monitored at an 
aggregate source level (unless specified otherwise), emissions from 
standby sources; and activity data for each aggregate source type 
level. Owners or operators of natural gas distribution facilities would 
report emissions at the individual station level.
    Additional data are proposed to be reported to support 
verification: Engineering estimate of total component count; total 
number of compressors and average operating hours per year in each mode 
of operation for compressors, if applicable; minimum, maximum and 
average throughput per year; and specification of the type of any 
control device used, including flares. For offshore petroleum and 
natural gas production facilities, the number of connected wells, and 
whether they are producing oil, gas, or both is proposed to be 
reported. For compressors specifically, EPA proposes that the total 
number of compressors of each type (reciprocating, centrifugal with dry 
seals and centrifugal with wet seals) and average operating hours per 
year be reported.
    A full list of data proposed to be reported is included in proposed 
40 CFR part 98, subparts A and W.

H. Selection of Records That Must Be Retained

    The owner or operator shall retain relevant information associated 
with the monitoring and reporting of emissions to EPA for three years 
as follows: Throughput of the facility when the emissions direct 
measurement was conducted; date(s) of measurement, detection and 
measurement instruments used, if any; and results of the emissions 
detection survey, including a video record of the leak survey.
    A full list of records proposed to be retained is included in 
proposed 40 CFR part 98, subparts A and W.

III. Economic Impacts of the Proposed Rule

    This section of the preamble examines the costs and economic 
impacts of this proposed supplemental rule, including the estimated 
costs and benefits of the rule, and the estimated economic impacts of 
the rule on affected entities, including estimated impacts on small 
entities. Complete details of the economic impacts of the final rule 
can be found in the text of the Economic Impact Analysis for the 
Mandatory Reporting of Greenhouse Gas Emissions under Subpart W 
Supplemental Rule (EPA-HQ-OAR-2009-0923). In brief, all equipment and 
labor activities for complying with each emissions estimate in the rule 
were analyzed by technical experts with relevant industry experience. 
The estimated labor hours and labor categories were applied to each 
industry segment, in some cases proportioned to small, medium and large 
facilities where such variation exists, to quantify the total labor 
hours, multiplied by Government statistics on labor rates, arriving at 
the total labor and equipment costs for the estimated numbers of 
sources. Administrative costs for reviewing the reporting rules, 
training personnel, documenting emissions data and emissions estimates, 
approving the submission to the EPA, submitting reports and maintaining 
records were included for each reporting company. These total bottom-up 
cost estimates were divided by the emissions captured to arrive at the 
dollar per metric ton, and divided by the number of reporting entities 
to arrive at average costs per entity. The methods proposed by EPA are 
a balance between minimizing these costs, maximizing emissions coverage 
and maximizing quality of emissions estimates. The cost to affected 
parties on a dollar per metric ton has been reduced by greater than 50 
percent when compared to the initial petroleum and natural gas 
proposal. To achieve this cost reduction, EPA significantly modified 
the rule to rely significantly less on direct measurement and more on 
engineering estimates, leaker factors and emissions factors. Table W-5 
and Table W-6 compare the first year and subsequent year costs, 
respectively, to reporters for reporting fugitive and vented emissions 
based on the reporting requirements proposed under the initial proposal 
as compared to the new supplemental proposed rule.

 Table W-5--Estimated First Year Cost for Reporting Fugitive and Vented Emissions for Petroleum and Natural Gas
                                                Systems, MMTCO2E
----------------------------------------------------------------------------------------------------------------
                                                      Initial proposed rule1         New supplemental proposed
                                                 --------------------------------           rulemaking
                     Segment                                                     -------------------------------
                                                       Cost       Cost per tonne       Cost       Cost per tonne
                                                    ($million)       ($/tonne)      ($million)       ($/tonne)
----------------------------------------------------------------------------------------------------------------
Original six segments...........................           $32.5           $0.38           $26.7           $0.28
Onshore Production..............................              NA              NA            27.7            0.18
Natural Gas Distribution........................              NA              NA             1.6            0.07
                                                 ---------------------------------------------------------------
    Total Segments..............................            32.5            0.38            56.0            0.21
----------------------------------------------------------------------------------------------------------------
\1\ The costs for the initial proposed rule, shown here, reflect the in-house monitoring option. Costs for the
  alternative contractor monitoring option can be found in Docket EPA-HQ-OAR-2008-0508-0138.


 TABLE W-6--Estimated Subsequent Year Cost for Reporting Fugitive and Vented Emissions for Petroleum and Natural
                                              Gas Systems, MMTCO2E
----------------------------------------------------------------------------------------------------------------
                                                       Initial proposed rule         New supplemental proposed
                                                 --------------------------------           rulemaking
                     Segment                                                     -------------------------------
                                                       Cost       Cost per tonne       Cost       Cost per tonne
                                                    ($million)       ($/tonne)      ($million)       ($/tonne)
----------------------------------------------------------------------------------------------------------------
Original six segments...........................           $28.1           $0.33            11.8           $0.13
Onshore Production..............................              NA              NA             8.6            0.06
Natural Gas Distribution........................              NA              NA             1.0            0.04
                                                 ---------------------------------------------------------------

[[Page 18626]]

 
    Total Segments..............................           $28.1           $0.33            21.4            0.08
----------------------------------------------------------------------------------------------------------------
\1\ Subsequent year in the initial proposed rule was defined as Year 2 whereas in the supplemental proposed rule
  it is defined as the average of Years 2, 3, and 4.

A. How were compliance costs estimated?

1. Summary of EPA's Consideration of Comments Received on the Initial 
Proposal
    A majority of the comments received on the compliance costs of the 
fugitive emissions reporting rule focused on facility level costs for 
detection and measurement of emissions. Commenters noted that costs 
estimated for certain petroleum and gas industry segments ignored 
available data on average leak factors. Some who commented specifically 
referred to government programs that gather similar, or in the case of 
offshore petroleum and gas production in the Gulf of Mexico Federal 
waters, some of the same data as required under Subpart W. Others who 
commented noted that Subpart W had higher estimated compliance costs 
than other sectors for much smaller GHG emissions.
    EPA recognizes that the costs presented for some petroleum and gas 
industry segments in the initial proposal were relatively high for 
smaller emissions quantified than other industry sectors. EPA also 
recognizes that for many fugitive and vented emissions sources, new 
data exist on component emission factors, and long established data may 
be justified for smaller, inaccessible to plain view or more burdensome 
to identify emission sources. Furthermore, EPA recognizes that other 
government programs gather similar or the same data as proposed by this 
rule.
    This proposed supplemental rule incorporates a number of different 
methodologies to provide improved emissions coverage at a lower cost 
burden to affected facilities. The approach used in determining the 
appropriate methodology for the supplemental was to minimize the use of 
direct measurement of emissions (which results in a higher cost burden 
to affected facilities) except for the most significant emissions 
sources where other options are not available, and to use engineering 
estimates, emissions modeling software, and leak detection and publicly 
available emission factors for most vented and fugitive sources. For 
smaller fugitive and inaccessible to plain view (i.e. buried or below 
grade in vaults) sources, component count and population emissions 
factors are proposed. In the case of Offshore platforms, EPA is 
recommending that emissions 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 all State waters. 
These alternative methodologies will provide similar or better coverage 
of vented and fugitive methane and carbon dioxide emissions in the 
petroleum and gas industry, while significantly reducing industry 
burden.
    As described in the next section, EPA collected and evaluated cost 
data from multiple sources, and weighed the analysis prepared at 
initial proposal against the input received through public comments. In 
any analysis of this type, there will be variations in costs among 
facilities, and after thoroughly reviewing the available information, 
we have concluded that the costs developed for this supplemental 
proposed rule in each petroleum and gas industry segment appropriately 
reflects a ``representative facility'' in those segments.
2. Summary of Method Used To Estimate Compliance Costs
    EPA estimated costs of complying with the rule for reporting 
fugitive and vented GHG emissions in each affected petroleum and gas 
industry facility, as well as emissions from stationary combustion 
sources at petroleum and gas industry facilities (for threshold and 
burden analysis only; stationary combustion is reported under Subpart 
C). This supplemental rulemaking proposes methodologies for reporting 
fugitive and vented emissions from oil and gas facilities. Once 
triggering the proposed rule, all of these facilities would also have 
to report emissions from stationary combustion. The costs of compliance 
for this proposed rule includes the costs associated with calculating 
and reporting fugitive and vented emissions, as well as the costs of 
any incremental combustion-related emissions that would be required to 
be reported by facilities (i.e., combustion emissions that were not 
already required to be reported under the final MRR). The 
representative year of the analysis is 2006 and all annual costs were 
estimated using the 2006 population of emitting sources. EPA used 
available industry and EPA data to characterize conditions at affected 
sources. Incremental monitoring, recordkeeping, and reporting 
activities were then identified for each type of facility and the 
associated costs were estimated.
    The costs of complying with the rule will vary from one petroleum 
and gas industry segment and facility to another, depending on the 
types of emissions, the number of affected sources at the facility, 
existing monitoring, recordkeeping, and reporting activities at the 
facility, etc. The costs include labor costs for developing a plan, 
setting up records, collecting field data, performing monitoring, 
inputting field data into engineering models, recordkeeping, and 
reporting activities necessary to comply with the rule. For some 
facilities, costs include expenditures related to monitoring, 
recording, and reporting both process emissions of GHGs and emissions 
from stationary combustion. For other facilities (e.g., LDCs), the only 
emissions of GHGs are process emissions. EPA's estimated costs of 
compliance are discussed in greater detail below:
    Labor Costs. The costs of complying with and administering this 
rule include time of managers, technical, operational and 
administrative staff in the private sector. Staff hours are estimated 
for activities, including:
     Developing a plan: reporting entity management and 
technical staff hours to applicability to the rule, organize 
indoctrination of rule requirements, identify staffing assignments, 
train staff, schedule activities as required below.

[[Page 18627]]

     Setting up records: technical and field staff hours to 
develop data collection sheets and analytical model equations or 
linkages to input data into standardized models
     Collecting field data: technical and field staff hours to 
collect necessary site-specific data and input that data into the 
analytical input tables.
     Monitoring: staff hours to procure, install, operate and 
maintain emissions monitoring equipment, instruments and engineering 
analysis systems.
     Engineering models: technical staff hours to link and 
execute engineering emissions estimation models and analytical 
procedures and to organize output data as required for reporting 
emissions.
     Record keeping: staff hours required to organize, file and 
secure critical data and emissions quantification results as required 
for reporting and for documenting determinations of facilities 
exceeding and not exceeding reporting thresholds.
     Reporting: management and staff hours to organize data, 
perform quality assurance/quality control, inform key management 
personnel, and reporting it to EPA through electronic systems.
    Staff activities and associated labor costs will vary from facility 
to facility and potentially vary over time where first year start-up 
costs are more significant and where site-specific emissions factors 
are developed every two or three years. Thus, cost estimates are 
developed for start-up and first-time reporting, and subsequent 
reporting. Wage rates to monetize staff time are obtained from the 
Bureau of Labor Statistics (BLS).
    Equipment Costs. Equipment costs include both the initial purchase 
price of monitoring equipment and any facility/process modification 
that may be required for installation and/or use of monitoring 
equipment. For example, the cost estimation method for large compressor 
seal emissions includes both purchase of a flow measurement instrument 
and installation of a measurement port in the vent piping where the end 
of the vent is inaccessible. Based on expert judgment, the engineering 
costs analyses annualized capital equipment costs with appropriate 
lifetime and interest rate assumptions. Cost recovery periods and 
interest rates vary by industry, but typically, one-time capital costs 
are amortized over a 10-year cost recovery period at a rate of seven 
percent.

B. What are the costs of the proposed rule?

1. Summary of Costs
    For the cost analysis, EPA gathered existing data from EPA studies 
and publications, industry trade associations and publicly available 
data sources (e.g., labor rates from the BLS) to characterize the 
processes, sources, sectors, facilities, and companies/entities 
affected. EPA also considered cost data submitted in public comments on 
the proposed rule. Costs were estimated on a per entity basis and then 
weighted by the number of entities affected at the 25,000 metric tons 
CO2e threshold.
    To develop the costs for the rule, EPA estimated the number of 
affected facilities in each source category, the number and types of 
process equipment at each facility, the number and types of processes 
that emit GHGs, process inputs and outputs (especially for monitoring 
procedures that involve a carbon mass balance), and the measurements 
that are already being made for reasons not associated with the rule 
(to allow only the incremental costs to be estimated). Many of the 
affected source categories, especially those that are the largest 
emitters of GHGs (e.g., glycol dehydrators, petroleum stock tanks, gas 
processing plants) are subject to national emission standards and we 
use data generated in the development of these standards to estimate 
the number of sources affected by the proposed reporting rule.
    Other components of the cost analysis included estimates of labor 
hours to perform specific activities, cost of labor, and cost of 
monitoring equipment. Estimates of labor hours were based on previous 
analyses of the costs of monitoring, reporting, and recordkeeping for 
other rules; information from the industry characterization on the 
number of units or process inputs and outputs to be monitored; and 
engineering judgment by industry and EPA industry experts and 
engineers. Labor costs were taken from the BLS and adjusted to account 
for overhead. Monitoring costs were generally based on cost algorithms 
or approaches that had been previously developed, reviewed, accepted as 
adequate, and used specifically to estimate the costs associated with 
various types of measurements and monitoring.
    A detailed engineering analysis was conducted for each petroleum 
and gas industry segment of this proposed rule to develop unique unit 
costs. This analysis is documented in the Economic Impact Analysis for 
the Mandatory Reporting of Greenhouse Gas Emissions under Subpart W 
Supplemental Rule (EPA-HQ-OAR-2009-0923). The Greenhouse Gas Emissions 
from the Petroleum and Natural Gas Industry: Background TSD (EPA-HQ-
OAR-2009-0923) provides a discussion of the applicable engineering 
estimating and measurement technologies and any existing programs and 
practices. Incremental combustion-related emissions that would be 
required to be reported by facilities (as noted above) were estimated 
using Tier 1 factors from Subpart C of the Final MRR. Section 4 of the 
Economic Impact Analysis for the proposed rule contains a description 
of the engineering cost analysis.
    Table W-7 of this preamble presents: the emissions covered under 
this proposed supplemental rule, the first year total costs and the 
first year cost per ton for process and combustion emissions, and these 
values for the subsequent years. EPA estimates that the total cost for 
process emissions in the first year is $56.0 million, and the total 
national annualized cost for subsequent years is $21.4 million (2006$). 
Of these costs, roughly 49.5 percent fall upon the onshore production 
segment in the first year, while 34.5 percent fall upon the gas 
transmission segment. Offshore production, which is largely covered by 
the MMS GOADS study data, is estimated to incur approximately 0.5 
percent of costs every three or four years; other segments incurring 
relatively large shares of costs are gas processing (12.5 percent) and 
local distribution companies (3 percent). The reporting of incremental 
combustion related emission for all segments of the petroleum and 
natural gas industry are estimated to cost $3.9 million in both the 
first and subsequent years.
    The threshold, in large part, determines the number of entities 
required to report GHG emissions and hence the costs of the rule. The 
number of entities excluded increases with higher thresholds. Table W-8 
of this preamble provides the cost-effectiveness analysis for various 
thresholds examined. Two metrics are used to evaluate the cost-
effectiveness of the emissions threshold. The first is the average cost 
per metric ton of emissions reported ($/metric ton CO2e). 
The second metric for evaluating the threshold option is the 
incremental cost of reporting emissions. The incremental cost is 
calculated as the additional (incremental) cost per metric ton starting 
with the least stringent option and moving successively from one 
threshold option to the next. For more information about the first year 
capital costs (unamortized), project lifetime and

[[Page 18628]]

the amortized (annualized) costs for each petroleum and gas industry 
segment please refer to section 4 of the Economic Analysis for the 
proposed rule. Not all segments require capital expenditures but those 
that do are clearly documented in the Economic Impact Analysis for the 
proposed rule.

                                        Table W-7--National Cost Estimates for Petroleum and Natural Gas Systems
                                                                         [2006$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                          First year                          Subsequent years
                                                                           -----------------------------------------------------------------------------
         Subpart W--petroleum and natural gas systems             NAICS     $million\1\                              $million
                                                                           -------------   Million       $/ton    -------------   Million       $/ton
                                                                                2006        MtCO2e                     2006        MtCO2e
--------------------------------------------------------------------------------------------------------------------------------------------------------
Fugitive and Vented Emissions................................     211, 486          $56        272.0        $0.21        $21.4        272.0        $0.08
Combustion Emissions.........................................  ...........          3.9         79.1         0.05          3.9         79.1         0.05
                                                              ------------------------------------------------------------------------------------------
    Total Private Sector Emissions...........................  ...........         59.9        351.1         0.17         25.3        351.1         0.07
--------------------------------------------------------------------------------------------------------------------------------------------------------


                                Table W-8--Threshold Cost-Effectiveness Analysis
                                            [Subsequent year, 2006$]
----------------------------------------------------------------------------------------------------------------
                                                                   Percentage of
   Threshold        Facilities      Total costs     Downstream         total          Average       Incremental
  (metric tons     required to       (million        emissions      downstream    reporting cost     cost  ($/
     CO2e)            report          $2006)         reported        emissions        ($/ton)       metric ton)
                                                   (MtCO2e/year)     reported                           \1\
----------------------------------------------------------------------------------------------------------------
        100,000            1,143          $13.66             273              64           $0.05           $0.05
         25,000            3,037           25.30             351              83            0.08            0.13
         10,000            4,884           38.62             380              90            0.10            0.23
          1,000           15,057           97.18             415              98            0.23            0.46
----------------------------------------------------------------------------------------------------------------
\1\ Cost per metric ton relative to the selected option.

C. What are the economic impacts of the proposed rule?

1. Summary of Economic Impacts
    EPA prepared an economic impact analysis to evaluate the impacts of 
the rule on affected small to large reporting entities. In evaluating 
the various reporting options considered, EPA conducted a cost-
effectiveness analysis, comparing the cost per metric ton of GHG 
emissions across reporting options. EPA used this information to 
identify the preferred options described in today's proposed rule.
    To estimate the economic impacts of the rule, EPA first conducted a 
screening assessment, comparing the estimated total annualized 
compliance costs for the petroleum and gas industry, where industry is 
defined in terms of North American Industry Classification System 
(NAICS) code, with industry average revenues. Overall national costs of 
the rule are significant because there are a large number of affected 
entities, but per-entity costs are low due to large coverage of 
emissions from these entities. Average cost-to-sales ratios for 
establishments in the affected NAICS codes for all segments is less 
than 1 percent, except in the 1-20 employee range for the onshore 
petroleum and natural gas segment.
    These low average cost-to-sales ratios indicate that the proposed 
rule is unlikely to result in significant changes in firms' production 
decisions or other behavioral changes, and thus unlikely to result in 
significant changes in prices or quantities in affected markets. Thus, 
EPA followed its Guidelines for Preparing Economic Analyses (EPA, 2002, 
p. 124-125) and used the engineering cost estimates to measure the 
social cost of the rule, rather than modeling market responses and 
using the resulting measures of social cost. Table W-9 of this preamble 
summarizes cost-to-sales ratios for affected industries.

                         Table W-9--Estimated Cost-to-Sales Ratios for Affected Entities
                                                    [Year 1]
----------------------------------------------------------------------------------------------------------------
                                                                              Average cost per   Average entity
                  NAICS                            NAICS description          entity  ($1,000/    cost-to-sales
                                                                                   entity)          ratio\1\
----------------------------------------------------------------------------------------------------------------
211.....................................  Crude Petroleum and Natural Gas                  $24             0.11%
                                           Extraction.
486210..................................  Pipeline Transportation of Natural                18             0.10%
                                           Gas.
221210..................................  Natural Gas Distribution..........                11             0.05%
----------------------------------------------------------------------------------------------------------------
\1\ This ratio reflects first year costs. Subsequent year costs will be slightly lower because they do not
  include initial start-up activities.


[[Page 18629]]

D. What are the impacts of the proposed rule on small businesses?

1. Summary of Impacts on Small Businesses
    As required by the RFA and Small Business Regulatory Enforcement 
and Fairness ACT (SBREFA), EPA assessed the potential impacts of the 
rule on small entities (small businesses, governments, and non-profit 
organizations). (See Section IV.C of this preamble for definitions of 
small entities.)
    EPA has determined the selected threshold maximizes the rule 
coverage with 83 percent of U.S. GHG emissions from the industry 
segments reported by approximately 3,037 reporters, while keeping 
reporting burden to a minimum. Furthermore, many industry stakeholders 
that EPA met with expressed support for a 25,000 metric ton 
CO2e threshold because it sufficiently captures the majority 
of GHG emissions in the U.S., while excluding most of the smaller 
facilities and sources. We received many comments related to monitoring 
and reporting requirements in specific source categories, and made many 
changes in response to reduce burden on reporters. For information on 
these issues, refer to the discussion of each segment in this preamble.
    EPA conducted a screening assessment comparing compliance costs to 
onshore petroleum and natural gas production specific receipts data for 
establishments owned by small businesses. This ratio constitutes a 
``sales'' test that computes the annualized compliance costs of this 
rule as a percentage of sales and determines whether the ratio exceeds 
one percent.\9\ The cost-to-sales ratios were constructed at the 
establishment level (average reporting program costs per establishment/
average establishment receipts) for several business size ranges. This 
allowed EPA to account for receipt differences between establishments 
owned by large and small businesses and differences in small business 
definitions across affected industries. The results of the screening 
assessment are shown in Table W-10 of this preamble.
---------------------------------------------------------------------------

    \9\ EPA's RFA guidance for rule writers suggests the ``sales'' 
test continues to be the preferred quantitative metric for economic 
impact screening analysis.

                                               Table W-10.--Estimated Cost-to-Sales Ratios for First Year Costs by Industry and Enterprise Size\a\
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                            Average                                         Owned by enterprises with:
                                                                      SBA Size  Standard   cost per              -------------------------------------------------------------------------------
             Industry                NAICS     NAICS Description     (effective March 11,   entity       All                                 100 to     500 to                750 to    1,000 to
                                                                            2008)          ($1,000/  enterprises       <20       20 to 99     499        749        <500       999       1,499
                                                                                            entity)               employees\f\  employees  employees  employees  employees  employees  employees
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Onshore petroleum and natural gas       211  Crude Petroleum and    500 employees........       $24      0.11%          1.83%       0.16%      0.07%      0.03%      0.65%      0.04%      0.03%
 production; offshore petroleum               Natural Gas
 and natural gas production; LNG              Extraction.
 storage; LNG import and export.
Onshore natural gas processing;      486210  Pipeline               7.5 million dollars..        18       0.10           0.14    0.47 \b\   0.28 \b\  .........       0.12  .........  .........
 onshore natural gas transmission;            Transportation of
 underground natural gas storage.             Natural Gas.
Natural gas distribution..........   221210  Natural Gas            7.5 million dollars..        11       0.05           0.22        0.02       0.05       0.09       0.06       0.02      0.02
                                              Distribution.
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. The enterprise
  and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise--the enterprise employment and annual payroll are summed from the
  associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments.
Since the SBA's business size definitions (http://www.sba.gov/size) apply to an establishment's ultimate parent company, we assume in this analysis that the enterprise definition above is
  consistent with the concept of ultimate parent company that is typically used for SBREFA screening analyses.
\2\ The Census Bureau has missing data ranges for this employee range. Hence the receipts are an underestimate of the true value. Therefore, the cost-to-sales ratio is a conservative estimate.

    As shown, the cost-to-sales ratios are less than one percent for 
establishments owned by small businesses that EPA considers most likely 
to be covered by the reporting program, except the ratio for 1-20 
employee range for crude petroleum and natural gas extraction, which is 
greater than 1 percent but less than 2 percent. The petroleum and 
natural gas industry has a large number of enterprises, the majority of 
them in the 1-20 employee range. However, a large fraction of 
production comes from large corporations and not those with less than 
20 employee enterprises. The smaller enterprises in most cases deal 
with very small operations (such as a single family owning a few 
production wells) that are unlikely to cross even the 25,000 metric 
tons CO2e threshold considered for the rule. An exception to 
such a scenario is a small (less than 20 employee) enterprise owning 
large operations but conducting nearly all of its operations through 
contractors. This is not an uncommon practice in the onshore petroleum 
and natural gas production segment. Such enterprises, however, are a 
very small group among the over 19,000 enterprises in the less than 20 
employee category and EPA proposes to cover them in the rule.
    EPA took a conservative approach with the model entity analysis. 
Although the appropriate SBA size definition should be applied at the 
parent company (enterprise) level, data limitations allowed us only to 
compute and compare ratios for a model establishment within several 
enterprise size ranges.
    Although this rule will not have a significant economic impact on a 
substantial number of small entities, the Agency nonetheless tried to 
reduce the impact of this rule on small entities, including seeking 
input from a wide range of private- and public-sector

[[Page 18630]]

stakeholders. When developing the rule, the Agency took special steps 
to ensure that the burdens imposed on small entities were minimal. The 
Agency conducted several meetings with industry trade associations to 
discuss regulatory options and the corresponding burden on industry, 
such as recordkeeping and reporting. The Agency investigated 
alternative thresholds and analyzed the marginal costs associated with 
requiring smaller entities with lower emissions to report. The Agency 
also recommended a hybrid method for reporting, which provides 
flexibility to entities and helps minimize reporting costs.

E. What are the benefits of the proposed rule for society?

    EPA examined the potential benefits of the proposed GHG reporting 
rule for petroleum and natural gas systems. The benefits of a reporting 
system are based on their relevance to policy making, transparency 
issues, and market efficiency. Benefits are very difficult to quantify 
and monetize. Instead of a quantitative analysis of the benefits, EPA 
conducted a systematic literature review of existing studies including 
government, consulting, and scholarly reports.
    A mandatory reporting system for petroleum and natural gas systems 
will benefit the public by increased transparency of facility emissions 
data. Transparent, public data on emissions allows for accountability 
of polluters to the public stakeholders who bear the cost of the 
pollution. Citizens, community groups, and labor unions have made use 
of data from Pollutant Release and Transfer Registers to negotiate 
directly with polluters to lower emissions, circumventing greater 
government regulation. Publicly available emissions data also will 
allow individuals to alter their consumption habits based on the GHG 
emissions of producers.
    The greatest benefit of mandatory reporting of petroleum and 
natural gas systems GHG emissions to government will be realized in 
developing future GHG policies. For example, in the European Union's 
Emissions Trading System, a lack of accurate monitoring at the facility 
level before establishing CO2 allowance permits resulted in 
allocation of permits for emissions levels an average of 15 percent 
above actual levels in every country except the United Kingdom.
    As the primary constituent of natural gas, methane is also an 
important energy source. As a result, methane emissions reductions can 
provide significant economic and environmental benefits. EPA has been 
working in collaboration with oil and natural companies in the U.S. as 
part of the Natural Gas STAR Program since 1993. Through this 
collaborative partnership program, EPA has identified over 120 proven, 
cost effective technologies and practices to reduce methane emissions 
across operations in all of the major industry sectors--production, 
gathering and processing, transmission, and distribution. The proposed 
reporting rule will increase knowledge of the location and magnitude of 
significant methane emissions sources in the oil and gas industry which 
can result in cross-cutting benefits on domestic energy supply, 
industrial efficiency and safety, and revenue generation.
    Benefits to industry of GHG emissions monitoring include the value 
of having independent, verifiable data to present to the public to 
demonstrate appropriate environmental stewardship, and a better 
understanding of their emission levels and sources to identify 
opportunities to reduce emissions. Such monitoring allows for inclusion 
of standardized GHG data into environmental management systems, 
providing the necessary information to achieve and disseminate their 
environmental achievements.
    Standardization will also be a benefit to industry, once facilities 
invest in the institutional knowledge and systems to report emissions, 
the cost of monitoring should fall and the accuracy of the accounting 
should improve. A standardized reporting program will also allow for 
facilities to benchmark themselves against similar facilities to 
understand better their relative standing within their industry.
    Section VI of the RIA for the Final MRR summarizes the anticipated 
benefits of the finalized rule, which include providing the government 
with sound data on which to base future policies and providing industry 
and the public independently verified information documenting firms' 
environmental performance. While EPA has not quantified the benefits of 
the mandatory reporting rule, EPA believes that they are substantial 
and outweigh the estimated costs.

IV. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993), 
this action is a ``significant regulatory action'' because it raises 
novel legal or policy issues arising out of legal mandates, the 
President's priorities, or the principles set forth in the EO. 
Accordingly, EPA submitted this action to the Office of Management and 
Budget (OMB) for review under EO 12866.

B. Paperwork Reduction Act

    The information collection requirements in this proposed rule have 
been submitted for approval to the Office of Management and Budget 
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The 
Information Collection Request (ICR) document prepared by EPA has been 
assigned EPA ICR number 2376.01.
    EPA plans to collect complete and accurate facility-level GHG 
emissions from the petroleum and natural gas industry. Accurate and 
timely information on GHG emissions is essential for informing future 
climate change policy decisions. Through data collected under this 
proposed rule, EPA will gain a better understanding of the relative 
emissions of different segments of the petroleum and natural gas 
industry and the distribution of emissions from individual facilities 
within those industries. The facility-specific data will also improve 
our understanding of the factors that influence GHG emission rates and 
actions that facilities are already taking to reduce emissions. 
Additionally, EPA will be able to track the trend of emissions from 
facilities within the petroleum and natural gas industry over time, 
particularly in response to policies and potential regulations. The 
data collected by this proposed rule will improve EPA's ability to 
formulate climate change policy options and to assess which segments of 
the petroleum and gas industry would be affected, and how these 
segments would be affected by the options.
    This information collection is mandatory and will be carried out 
under CAA section 114. Information identified and marked as CBI will 
not be disclosed except in accordance with procedures set forth in 40 
CFR part 2. However, emissions data collected under CAA section 114 
cannot generally be claimed as CBI and will be made public.\10\
---------------------------------------------------------------------------

    \10\ Although CBI determinations are usually made on a case-by-
case basis, EPA has issued guidance in an earlier Federal Register 
notice on what constitutes emissions data that cannot be considered 
CBI (956 FR 7042-7043, February 21, 1991). As discussed in Section 
II.R of the Final MRR preamble, EPA is initiating a separate notice 
and comment process to make CBI determinations for the data 
collected under this rulemaking. EPA intends to issue this notice in 
early 2010, and will include in the notice the data proposed for 
collection in this rulemaking.
---------------------------------------------------------------------------

    The projected cost and hour burden for non-federal respondents is 
$37.8 million and 478,774 hours per year. The

[[Page 18631]]

estimated average burden per response is 98.2 hours; the frequency of 
response is annual for all respondents that must comply with the 
proposed rule's reporting requirements; and the estimated average 
number of likely respondents per year is 3,038. The cost burden to 
respondents resulting from the collection of information includes the 
total capital cost annualized over the equipment's expected useful life 
(averaging $5.3 million), a total operation and maintenance component 
(averaging $1.6 million per year), and a labor cost component 
(averaging $30.9 million per year).\11\ Burden is defined at 5 CFR 
1320.3(b).
---------------------------------------------------------------------------

    \11\ Burden is defined at 5 CFR 1320.3(b). These cost numbers 
differ from those shown elsewhere in the Economic Analysis because 
the ICR costs represent the average cost over the first three years 
of the proposed rule, but costs are reported elsewhere in the 
Economic Analysis for the first year of the proposed rule and for 
subsequent years of the proposed rule. In addition, the ICR focuses 
on respondent burden, while the Economic Analysis includes EPA 
Agency costs.
---------------------------------------------------------------------------

    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for EPA's 
regulations in 40 CFR are listed in 40 CFR part 9.
    To comment on the Agency's need for this information, the accuracy 
of the provided burden estimates, and any suggested methods for 
minimizing respondent burden, EPA has established a public docket for 
this rule, which includes this ICR, under Docket ID number (EPA-HQ-OAR-
2009-0923). Submit any comments related to the ICR to EPA and OMB. See 
ADDRESSES section at the beginning of this notice for where to submit 
comments to EPA. Send comments to OMB at the Office of Information and 
Regulatory Affairs, Office of Management and Budget, 725 17th Street, 
NW., Washington, DC 20503, Attention: Desk Office for EPA. Since OMB is 
required to make a decision concerning the ICR between 30 and 60 days 
after April 12, 2010, a comment to OMB is best assured of having its 
full effect if OMB receives it by May 12, 2010. The final rule will 
respond to any OMB or public comments on the information collection 
requirements contained in this proposal.

C. Regulatory Flexibility Act (RFA)

    The RFA generally requires an agency to prepare a regulatory 
flexibility analysis of any rule subject to notice and comment 
rulemaking requirements under the Administrative Procedure Act or any 
other statute unless the agency certifies that the rule will not have a 
significant economic impact on a substantial number of small entities. 
Small entities include small businesses, small organizations, and small 
governmental jurisdictions.
    For purposes of assessing the impacts of this proposed rule on 
small entities, small entity is defined as: (1) A small business as 
defined by the Small Business Administration's regulations at 13 CFR 
121.201; (2) a small governmental jurisdiction that is a government of 
a city, county, town, school district or special district with a 
population of less than 50,000; and (3) a small organization that is 
any not-for-profit enterprise which is independently owned and operated 
and is not dominant in its field.
    After considering the economic impacts of today's proposed rule on 
small entities, I certify that this action will not have a significant 
economic impact on a substantial number of small entities. The small 
entities directly regulated by this proposed rule include small 
businesses in the petroleum and natural gas industry, small 
governmental jurisdictions and small non-profits. We have determined 
that some small businesses will be affected because their production 
processes emit GHGs that must be reported.
    The small entities directly regulated by this proposed rule include 
small businesses in the petroleum and gas industry, small governmental 
jurisdictions and small non-profits. We have determined that some small 
businesses will be affected because their production processes emit 
GHGs that must be reported.
    For affected small entities, EPA conducted a screening assessment 
comparing compliance costs for affected industry segments to petroleum 
and gas-specific data on revenues for small businesses. This ratio 
constitutes a ``sales'' test that computes the annualized compliance 
costs of this proposed rule as a percentage of sales and determines 
whether the ratio exceeds some level (e.g., 1 percent or 3 percent). 
The cost-to-sales ratios were constructed at the establishment level 
(average compliance cost for the establishment/average establishment 
revenues).
    As shown in Table W-10, the average ratio of annualized reporting 
program costs to receipts of establishments owned by model small 
enterprises was less than 1 percent for industries presumed likely to 
have small businesses covered by the reporting program. Although the 
costs to receipts for entities with 1-20 employees is over 1 percent, 
these facilities would likely not exceed the proposed 25,000 
mtCO2e threshold, a threshold supported by many stakeholders 
as one that sufficiently captures the majority of GHG emissions while 
excluding small facilities. Further, these sales tests examine the 
average establishment's total annualized mandatory reporting costs to 
the average establishment receipts for enterprises within several 
employment categories. The average entity costs used to compute the 
sales test are the same across all of these enterprise size categories. 
As a result, the sales-test will overstate the cost-to-receipt ratio 
for establishments owned by small businesses, because the reporting 
costs are likely lower than average entity estimates provided by the 
engineering cost analysis.
    The screening analysis thus indicates that the proposed rule will 
not have a significant economic impact on a substantial number of small 
entities. The screening assessment for small governments for the Final 
MRR compared the sum of average costs of compliance for combustion, 
local distribution companies, and landfills to average revenues for 
small governments. Even for a small government owning all three source 
types, the costs constitute less than 1 percent of average revenues for 
the smallest category of governments (those with fewer than 10,000 
people).
    Although this proposed rule will not have a significant economic 
impact on a substantial number of small entities, EPA nonetheless took 
several steps to reduce the impact of this proposed rule on small 
entities. For example, EPA determined appropriate thresholds that 
reduce the number of small businesses reporting. In addition, EPA is 
proposing different monitoring methods for different emissions sources, 
requiring direct measurement only for selected sources. Also, EPA is 
proposing annual instead of more frequent reporting.
    Through comprehensive outreach activities prior to proposal of the 
initial rule, EPA held approximately 100 meetings and/or conference 
calls with representatives of the primary audience groups, including 
numerous trade associations and industries in the petroleum and gas 
industry that include small business members. EPA's outreach activities 
prior to proposal of the initial rule are documented in the memorandum, 
``Summary of EPA Outreach Activities for Developing the Greenhouse Gas 
Reporting Rule,'' located in Docket No. EPA-HQ-OAR-2008-0508-053. After 
the initial proposal, EPA posted a guide for small businesses on the 
EPA GHG reporting rule Web site, along with a general fact sheet for 
the rule, information sheets for every source category, and an FAQ 
document. EPA also operated a hotline

[[Page 18632]]

to answer questions about the proposed rule. We continued to meet with 
stakeholders and entered documentation of all meetings into the docket.
    During rule implementation, EPA would maintain an ``open door'' 
policy for stakeholders to ask questions about the proposed rule or 
provide suggestions to EPA about the types of compliance assistance 
that would be useful to small businesses. EPA intends to develop a 
range of compliance assistance tools and materials and conduct 
extensive outreach for the proposed rule.
    We have therefore concluded that today's proposed rule will not 
have a significant economic impact on a substantial number of small 
entities. We continue to be interested in the potential impacts of the 
proposed rule on small entities and welcome comments on issues related 
to such impacts.

D. Unfunded Mandates Reform Act (UMRA)

    The UMRA seeks to protect State, local, and Tribal governments from 
the imposition of unfunded Federal mandates. In addition, the Act seeks 
to strengthen the partnership between the Federal government and State, 
local, and Tribal governments and ensure that the Federal government 
covers the costs incurred during compliance with Federal mandates.
    Title II of the UMRA of 1995, Public Law 104-4, establishes 
requirements for Federal agencies to assess the effects of their 
regulatory actions on State, local, and tribal governments and the 
private segment. Under section 202 of UMRA, EPA generally must prepare 
a written statement, including a cost-benefit analysis, for proposed 
and final rules with Federal mandates that may result in expenditures 
to State, local, and Tribal governments, in the aggregate, or to the 
private segment, of $100 million or more in any one year.
    Before promulgating an EPA rule for which a written statement is 
needed, section 205 of UMRA generally requires EPA to identify and 
consider a reasonable number of regulatory alternatives and adopt the 
least costly, most cost-effective or least burdensome alternative that 
achieves the objectives of the rule. The provisions of section 205 do 
not apply when they are inconsistent with applicable law. Moreover, 
section 205 allows EPA to adopt an alternative other than the least 
costly, most cost-effective or least burdensome alternative if the 
Administrator publishes with the final rule an explanation why that 
alternative was not adopted.
    Before EPA establishes any regulatory requirements that may 
significantly or uniquely affect small governments, including Tribal 
governments, it must have developed under section 203 of UMRA a small 
government agency plan. The plan must provide for notifying potentially 
affected small governments, enabling officials of affected small 
governments to have meaningful and timely input in the development of 
EPA regulatory proposals with significant Federal intergovernmental 
mandates, and informing, educating, and advising small governments on 
compliance with the regulatory requirements.
    EPA has determined that the Subpart W rule does not contain a 
Federal mandate that may result in expenditures of $100 million or more 
for State, local, and Tribal governments, in the aggregate, or the 
private segment in any one year. Expenditures associated with 
compliance, defined as the incremental costs beyond the existing 
regulations will not surpass $100 million in the aggregate in any year. 
Thus, today's rule is not subject to the requirements of sections 202 
and 205 of UMRA.
    This rule is also not subject to the requirements of section 203 of 
UMRA because it contains no regulatory requirements that might 
significantly or uniquely affect small governments. This regulation 
applies to facilities that directly emit greenhouse gases. It does not 
apply to governmental entities unless the government entity owns a 
facility in the petroleum and gas industry that directly emits 
greenhouse gases above threshold levels. In addition, this proposed 
rule does not impose any implementation responsibilities on State, 
local, or Tribal governments and it is not expected to increase the 
cost of existing regulatory programs managed by those governments. 
Thus, the impact on governments affected by the proposed rule is 
expected to be minimal.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have 
substantial direct effects on the States, on the relationship between 
the national government and the States, or on the distribution of power 
and responsibilities among the various levels of government, as 
specified in Executive Order 13132. This regulation applies directly to 
petroleum and natural gas facilities that emit greenhouse gases. Few, 
if any, state or local government facilities would be affected. This 
regulation also does not limit the power of States or localities to 
collect GHG data and/or regulate GHG emissions. Thus, Executive Order 
13132 does not apply to this action.
    In the spirit of Executive Order 13132, and consistent with EPA 
policy to promote communications between EPA and State and local 
governments, EPA specifically solicits comment on this proposed action 
from State and local officials.

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

    EPA has concluded that this action may have tribal implications. 
However, it will neither impose substantial direct compliance costs on 
tribal governments, nor preempt Tribal law. This regulation would apply 
directly to petroleum and natural gas facilities that emit greenhouses 
gases. Although few facilities that would be subject to the rule are 
likely to be owned by tribal governments, EPA has sought opportunities 
to provide information to tribal governments and representatives during 
rule development. EPA consulted with tribal officials early in the 
process of developing this regulation to permit them to have meaningful 
and timely input into its development. EPA sought opportunities to 
provide information to Tribal governments and representatives during 
development of the mandatory GHG reporting rule that was proposed in 
April 2009 and finalized in September 2009. Today's action is a 
supplemental proposal to that rule. In consultation with EPA's American 
Indian Environment Office, EPA's outreach plan included tribes. EPA 
conducted several conference calls with Tribal organizations during the 
proposal phase. For example, EPA staff provided information to tribes 
through conference calls with multiple Indian working groups and 
organizations at EPA that interact with tribes and through individual 
calls with two Tribal board members of TCR. In addition, EPA prepared a 
short article on the GHG reporting rule that appeared on the front page 
of a Tribal newsletter--Tribal Air News--that was distributed to EPA/
OAQPS's network of Tribal organizations. EPA gave a presentation on 
various climate efforts, including the mandatory reporting rule, at the 
National Tribal Conference on Environmental Management on June 24-26, 
2008. In addition, EPA had copies of a short information sheet 
distributed at a meeting of the National Tribal Caucus. See the 
``Summary of EPA Outreach Activities for Developing the GHG reporting 
rule,'' in Docket No. EPA-HQ-OAR-2008-0508-055 for a complete list of 
Tribal contacts. EPA

[[Page 18633]]

participated in a conference call with Tribal air coordinators in April 
2009 and prepared a guidance sheet for Tribal governments on the 
proposed rule. It was posted on the MRR Web site and published in the 
Tribal Air Newsletter.
    EPA specifically solicits additional comment on this proposed rule 
from Tribal officials.

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

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

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

    This proposed rule is not a ``significant energy action'' as 
defined in EO 13211 (66 FR 28355, May 22, 2001) because it is not 
likely to have a significant adverse effect on the supply, 
distribution, or use of energy. Further, we have concluded that this 
proposed rule is not likely to have any adverse energy effects. This 
proposed rule relates to monitoring, reporting and recordkeeping at 
petroleum and gas facilities that emit over 25,000 mtCO2e 
and does not impact energy supply, distribution or use. Therefore, we 
conclude that this proposed rule is not likely to have any adverse 
effects on energy supply, distribution, or use.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (NTTAA), Public Law 104-113 (15 U.S.C. 272 note) directs 
EPA to use voluntary consensus standards in its regulatory activities 
unless to do so would be inconsistent with applicable law or otherwise 
impractical. Voluntary consensus standards are technical standards 
(e.g., materials specifications, test methods, sampling procedures, and 
business practices) that are developed or adopted by voluntary 
consensus standards bodies. NTTAA directs EPA to provide Congress, 
through OMB, explanations when the Agency decides not to use available 
and applicable voluntary consensus standards.
    This rulemaking involves technical standards. EPA provides the 
flexibility to use any one of the voluntary consensus standards from at 
least seven different voluntary consensus standards bodies, including 
the following: ASTM, ASME, ISO, Gas Processors Association, and 
American Gas Association. These voluntary consensus standards will help 
facilities monitor, report, and keep records of greenhouse gas 
emissions. No new test methods were developed for this proposed rule. 
Instead, from existing rules for source categories and voluntary 
greenhouse gas programs, EPA identified existing means of monitoring, 
reporting, and keeping records of greenhouse gas emissions. The 
existing methods (voluntary consensus standards) include a broad range 
of measurement techniques, including many for combustion sources such 
as methods to analyze fuel and measure its heating value; methods to 
measure gas or liquid flow; and methods to gauge and measure petroleum 
and petroleum products.
    By incorporating voluntary consensus standards into this proposed 
rule, EPA is both meeting the requirements of the NTTAA and presenting 
multiple options and flexibility for measuring greenhouse gas 
emissions.

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

    Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes 
federal executive policy on environmental justice. Its main provision 
directs Federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the United States.
    EPA has determined that this proposed rule will not have 
disproportionately high and adverse human health or environmental 
effects on minority or low-income populations because it does not 
affect the level of protection provided to human health or the 
environment because it is a rule addressing information collection and 
reporting procedures.

List of Subjects in 40 CFR Part 98

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

    Dated: March 22, 2010.
Lisa P. Jackson,
Administrator.

    For the reasons stated in the preamble, the Environmental 
Protection Agency proposes to amend 40 CFR part 98 as follows:

PART 98--MANDATORY GREENHOUSE GAS REPORTING

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

    Authority: 42 U.S.C. 7401, et seq.

Subpart A--[Amended]

    2. Section 98.2 is amended by revising paragraph (a) introductory 
text to read as follows:


Sec.  98.2  Who must report?

    (a) The GHG reporting requirements and related monitoring, 
recordkeeping, and reporting requirements of this part apply to the 
owners and operators of any facility that is located in the United 
States or under or attached to the Outer Continental Shelf (as defined 
in 43 U.S.C. 1331) and that meets the requirements of either paragraph 
(a)(1), (a)(2), or (a)(3) of this section; and any supplier that meets 
the requirements of paragraph (a)(4) of this section:
* * * * *
    3. Section 98.6 is amended by adding the following definitions in 
alphabetical order and revising the definition of ``United States'' to 
read as follows:


Sec.  98.6  Definitions.

    Absorbent circulation pump means a pump commonly powered by natural 
gas pressure that circulates the absorbent liquid between the absorbent 
regenerator and natural gas contactor.
* * * * *
    Acid Gas means hydrogen sulfide (H2S) and carbon dioxide 
(CO2) contaminants that are separated from sour natural gas 
by an acid gas removal.
    Acid Gas Removal unit (AGR) means a process unit that separates 
hydrogen sulfide and/or carbon dioxide from sour natural gas using 
liquid or solid absorbents or membrane separators.
    Acid gas removal vent stack emissions mean the acid gas separated 
from the acid gas absorbing medium (e.g., an amine solution) and 
released with methane and other light hydrocarbons to the atmosphere or 
a flare.
* * * * *
    Air injected flare means a flare in which air is blown into the 
base of a flare stack to induce complete combustion of low Btu natural 
gas (i.e.,

[[Page 18634]]

high non-combustible component content).
* * * * *
    Blowdown vent stack emissions mean natural gas released due to 
maintenance and/or blowdown operations including but not limited to 
compressor blowdown and emergency shut-down (ESD) system testing.
* * * * *
    Calibrated bag means a flexible, non-elastic, anti-static bag of a 
calibrated volume that can be affixed to a emitting source such that 
the emissions inflate the bag to its calibrated volume.
* * * * *
    Centrifugal compressor means any equipment that increases the 
pressure of a process natural gas by centrifugal action, employing 
rotating movement of the driven shaft.
    Centrifugal compressor dry seals mean a series of rings around the 
compressor shaft where it exits the compressor case that operates 
mechanically under the opposing forces to prevent natural gas from 
escaping to the atmosphere.
    Centrifugal compressor dry seals emissions mean natural gas 
released from a dry seal vent pipe and/or the seal face around the 
rotating shaft where it exits one or both ends of the compressor case.
    Centrifugal compressor wet seal degassing venting emissions means 
emissions that occur when the high-pressure oil barriers for 
centrifugal compressors are depressurized to release absorbed natural 
gas. High-pressure oil is used as a barrier against escaping gas in 
centrifugal compressor shafts. Very little gas escapes through the oil 
barrier, but under high pressure, considerably more gas is absorbed by 
the oil. The seal oil is purged of the absorbed gas (using heaters, 
flash tanks, and degassing techniques) and recirculated. The separated 
gas is commonly vented to the atmosphere.
* * * * *
    Coal Bed Methane (CBM) means natural gas which is extracted from 
underground coal deposits or ``beds.''
* * * * *
    Component, for the purposes of subpart W only, means but is not 
limited to each metal to metal joint or seal of non-welded connection 
separated by a compression gasket, screwed thread (with or without 
thread sealing compound), metal to metal compression, or fluid barrier 
through which natural gas or liquid can escape to the atmosphere.
    Compressor means any machine for raising the pressure of a natural 
gas by drawing in low pressure natural gas and discharging 
significantly higher pressure natural gas.
* * * * *
    Condensate means hydrocarbon and other liquid separated from 
natural gas that condenses due to changes in the temperature, pressure, 
or both, and remains liquid at storage conditions, includes both water 
and hydrocarbon liquids.
* * * * *
    Conventional wells mean gas wells in producing fields that do not 
employ hydraulic fracturing to produce commercially viable quantities 
of natural gas.
* * * * *
    Dehydrator means a device in which a liquid absorbent (including 
but not limited to desiccant, ethylene glycol, diethylene glycol, or 
triethylene glycol) directly contacts a natural gas stream to absorb 
water vapor.
    Dehydrator vent stack emissions means natural gas released from a 
natural gas dehydrator system absorbent (typically glycol) reboiler or 
regenerator, including stripping natural gas and motive natural gas 
used in absorbent circulation pumps.
* * * * *
    De-methanizer means the natural gas processing unit that separates 
methane rich residue gas from the heavier hydrocarbons (e.g., ethane, 
propane, butane, pentane-plus) in feed natural gas stream).
* * * * *
    Desiccant means a material used in solid-bed dehydrators to remove 
water from raw natural gas by adsorption. Desiccants include activated 
alumina, palletized calcium chloride, lithium chloride and granular 
silica gel material. Wet natural gas is passed through a bed of the 
granular or pelletized solid adsorbent in these dehydrators. As the wet 
gas contacts the surface of the particles of desiccant material, water 
is adsorbed on the surface of these desiccant particles. Passing 
through the entire desiccant bed, almost all of the water is adsorbed 
onto the desiccant material, leaving the dry gas to exit the contactor.
* * * * *
    E&P Tank means the most current version of an exploration and 
production field tank emissions equilibrium program that estimates 
flashing, working and standing losses of hydrocarbons, including 
methane, from produced crude oil and gas condensate. Equal or 
successors to E&P Tank Version 2.0 for Windows Software. Copyright (C) 
1996-1999 by The American Petroleum Institute and The Gas Research 
Institute.
* * * * *
    Engineering estimation, for purposes of subpart W, means an 
estimate of emissions based on engineering principles applied to 
measured and/or approximated physical parameters such as dimensions of 
containment, actual pressures, actual temperatures, and compositions.
    Enhanced Oil Recovery (EOR) means the use of certain methods such 
as water flooding or gas injection into existing wells to increase the 
recovery of crude oil from a reservoir. In the context of this rule, 
EOR applies to injection of critical phase carbon dioxide into a crude 
oil reservoir to enhance the recovery of oil.
* * * * *
    Field means standardized field names and codes of all oil and gas 
fields identified in the United States as defined by the Energy 
Information Administration Oil and Gas Field Code Master List.
* * * * *
    Flare combustion means unburned hydrocarbons including 
CH4, CO2, N2O emissions resulting from 
the incomplete combustion of gas in flares.
    Flare combustion efficiency means the fraction of natural gas, on a 
volume or mole basis, that is combusted at the flare burner tip.
* * * * *
    Fugitive emissions means those emissions which are unintentional 
and could not reasonably pass through a stack, chimney, vent, or other 
functionally-equivalent opening.
    Fugitive emissions detection means the process of identifying 
emissions from equipment, components, and other point sources.
    Gas conditions mean the actual temperature, volume, and pressure of 
a gas sample.
* * * * *
    Gas gathering/booster stations mean centralized stations where 
produced natural gas from individual wells is co-mingled, compressed 
for transport to processing plants, transmission and distribution 
systems, and other gathering/booster stations which co-mingle gas from 
multiple production gathering/booster stations. Such stations may 
include gas dehydration, gravity separation of liquids (both 
hydrocarbon and water), pipeline pig launchers and receivers, and gas 
powered pneumatic devices.
* * * * *
    Gas to oil ratio (GOR) means the ratio of the volume of gas at 
standard

[[Page 18635]]

temperature and pressure that is produced from a volume of oil when 
depressurized to standard temperature and pressure.
* * * * *
    High-Bleed Pneumatic Devices are automated flow control devices 
powered by pressurized natural gas and used for maintaining a process 
condition such as liquid level, pressure, delta-pressure and 
temperature. Part of the gas power stream which is regulated by the 
process condition flows to a valve actuator controller where it vents 
(bleeds) to the atmosphere at a rate in excess of six standard cubic 
feet per hour.
* * * * *
    Liquefied natural gas (LNG) means natural gas (primarily methane) 
that has been liquefied by reducing its temperature to -260 degrees 
Fahrenheit at atmospheric pressure.
    LNG boiloff gas means natural gas in the gaseous phase that vents 
from LNG storage tanks due to ambient heat leakage through the tank 
insulation and heat energy dissipated in the LNG by internal pumps.
    Low-Bleed Pneumatic Devices mean automated flow control devices 
powered by pressurized natural gas and used for maintaining a process 
condition such as liquid level, pressure, delta-pressure and 
temperature. Part of the gas power stream which is regulated by the 
process condition flows to a valve actuator controller where it vents 
(bleeds) to the atmosphere at a rate equal to or less than six standard 
cubic feet per hour.
* * * * *
    Natural gas driven pneumatic pump means a pump that uses 
pressurized natural gas to move a piston or diaphragm, which pumps 
liquids on the opposite side of the piston or diaphragm.
* * * * *
    Offshore means seaward of the terrestrial borders of the United 
States, including waters subject to the ebb and flow of the tide, as 
well as adjacent bays, lakes or other normally standing waters, and 
extending to the outer boundaries of the jurisdiction and control of 
the United States under the Outer Continental Shelf Lands Act.
* * * * *
    Onshore petroleum and natural gas production owner or operator 
means the entity who is the permitee to operate petroleum and natural 
gas wells on the state drilling permit or a state operating permit 
where no drilling permit is issued by the state, which operates an 
onshore petroleum and/or natural gas production facility (as described 
in Sec.  98.230(b)(2). Where more than one entity are permitees on the 
state drilling permit, or operating permit where no drilling permit is 
issued by the state, the permitted entities for the joint facility must 
designate one entity to report all emissions from the joint facility.
* * * * *
    Operating pressure means the containment pressure that 
characterizes the normal state of gas or liquid inside a particular 
process, pipeline, vessel or tank.
* * * * *
    Outer Continental Shelf means all submerged lands lying seaward and 
outside of the area of lands beneath navigable waters as defined in 43 
U.S.C. Sec.  1301, and of which the subsoil and seabed appertain to the 
United States and are subject to its jurisdiction and control.
* * * * *
    Pump means a device used to raise pressure, drive, or increase flow 
of liquid streams in closed or open conduits.
    Pump seals means any seal on a pump drive shaft used to keep 
methane and/or carbon dioxide containing light liquids from escaping 
the inside of a pump case to the atmosphere.
    Pump seal emissions means hydrocarbon gas released from the seal 
face between the pump internal chamber and the atmosphere.
* * * * *
    Reciprocating compressor means a piece of equipment that increases 
the pressure of a process natural gas by positive displacement, 
employing linear movement of a shaft driving a piston in a cylinder.
    Reciprocating compressor rod packing means a series of flexible 
rings in machined metal cups that fit around the reciprocating 
compressor piston rod to create a seal limiting the amount of 
compressed natural gas that escapes to the atmosphere.
    Re-condenser means heat exchangers that cool compressed boil-off 
gas to a temperature that will condense natural gas to a liquid.
* * * * *
    Reservoir means a porous and permeable underground natural 
formation containing significant quantities of hydrocarbon liquids and/
or gases. A reservoir is characterized by a single natural pressure 
system.
* * * * *
    Sales oil means produced crude oil or condensate measured at the 
production lease automatic custody transfer (LACT) meter or custody 
transfer meter tank gauge.
* * * * *
    Sour natural gas means natural gas that contains significant 
concentrations of hydrogen sulfide and/or carbon dioxide that exceed 
the concentrations specified for commercially saleable natural gas 
delivered from transmission and distribution pipelines.
* * * * *
    Sweet Gas is natural gas with low concentrations of hydrogen 
sulfide (H2S) and/or carbon dioxide (CO2) that 
does not require (or has already had) acid gas treatment to meet 
pipeline corrosion-prevention specifications for transmission and 
distribution.
* * * * *
    Transmission pipeline means high pressure cross country pipeline 
transporting sellable quality natural gas from production or natural 
gas processing to natural gas distribution pressure let-down, metering, 
regulating stations where the natural gas is typically odorized before 
delivery to customers.
* * * * *
    Turbine meter means a flow meter in which a gas or liquid flow rate 
through the calibrated tube spins a turbine from which the spin rate is 
detected and calibrated to measure the fluid flow rate.
* * * * *
    Unconventional wells means gas well in producing fields that employ 
hydraulic fracturing to enhance gas production volumes.
* * * * *
    United States means the 50 States, the District of Columbia, the 
Commonwealth of Puerto Rico, American Samoa, the Virgin Islands, Guam, 
and any other Commonwealth, territory or possession of the United 
States, as well as the territorial sea as defined by Presidential 
Proclamation No. 5928.
* * * * *
    Vapor recovery system means any equipment located at the source of 
potential gas emissions to the atmosphere or to a flare, that is 
composed of piping, connections, and, if necessary, flow-inducing 
devices, and that is used for routing the gas back into the process as 
a product and/or fuel.
    Vaporization unit means a process unit that performs controlled 
heat input to vaporize LNG to supply transmission and distribution 
pipelines or consumers with natural gas.
* * * * *
    Vented emissions means intentional or designed releases of 
CH4 or CO2 containing natural gas or hydrocarbon 
gas (not including stationary combustion flue gas), including but not 
limited to process designed flow to the

[[Page 18636]]

atmosphere through seals or vent pipes, equipment blowdown for 
maintenance, and direct venting of gas used to power equipment (such as 
pneumatic devices).
* * * * *
    Well completions means a process that allows for the flow of 
petroleum or natural gas from newly drilled wells to expel drilling and 
reservoir fluids and test the reservoir flow characteristics. This 
process includes high-rate back-flow of injected water and sand used to 
fracture and prop-open fractures in low permeability gas reservoirs.
    Well workover means the performance of one or more of a variety of 
remedial operations on producing oil and gas wells to try to increase 
production. This process also includes high-rate back-flow of injected 
water and sand used to re-fracture and prop-open new fractures in 
existing low permeability gas reservoirs.
    Wellhead means the piping, casing, tubing and connected valves 
protruding above the Earth's surface for an oil and/or natural gas 
well. The wellhead ends where the flow line connects to a wellhead 
valve.
    Wet natural gas means natural gas in which water vapor exceeds the 
concentration specified for commercially saleable natural gas delivered 
from transmission and distribution pipelines. This input stream to a 
natural gas dehydrator is referred to as ``wet gas''.
    4. Section 98.7 is amended by adding paragraphs (k), (l), and (m) 
to read as follows:


Sec.  98.7  What standardized methods are incorporated by reference 
into this part?

* * * * *
    (k) The following material is available for purchase from the Gas 
Technology Institute, 1700 South Mount Prospect Road, Des Plaines, 
Illinois 60018, http://www.gastechnology.org.
    (1) GRI-GLYCalc Version 4.0, IBR approved for Sec.  98.233(e).
    (2) [Reserved]
    (l) The following material is available for purchase from IHS 
Standards Store, Jane's Information Group, Inc., 110 North Royal 
Street, Suite 200, Alexandria, Virginia 22314, http://www.ihs.com.
    (1) E&P Tank Version 2.0, IBR approved for Sec.  98.233(j) and 
Sec.  98.236(c).
    (2) [Reserved]
    (m) The following material is available for purchase from the 
American Association of Petroleum Geologists, 1444 South Boulder 
Avenue, Tulsa, Oklahoma 74119, www.aapg.org.
    (1) AAPG-CSD Geologic Provinces Code Map: AAPG Bulletin, Volume 75, 
Number 10 (October 1991), pages 1644-1651, IBR approved for Sec.  
98.230(b).
    (2) [Reserved]
    5. Add subpart W to read as follows:

Subpart W--Petroleum and Natural Gas Systems
Sec.
98.230 Definition of the source category.
98.231 Reporting threshold.
98.232 GHGs to report.
98.233 Calculating GHG emissions.
98.234 Monitoring and QA/QC requirements.
98.235 Procedures for estimating missing data.
98.236 Data reporting requirements.
98.237 Records that must be retained.
98.238 Definitions.

Subpart W--Petroleum and Natural Gas Systems


Sec.  98.230  Definition of the source category.

    (a) This source category consists of the following:
    (1) 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.
    (2) Onshore petroleum and natural gas production. Onshore petroleum 
and natural gas production equipment means all structures associated 
with wells (including but not limited to compressors, generators, or 
storage facilities), piping (including but not limited to flowlines or 
intra-facility gathering lines), and portable non-self-propelled 
equipment (including but not limited to well drilling and completion 
equipment, workover equipment, gravity separation equipment, auxiliary 
non-transportation-related equipment, and leased, rented or contracted 
equipment) used in the production, extraction, recovery, lifting, 
stabilization, separation or treating of petroleum and/or natural gas 
(including condensate). This also includes associated storage or 
measurement and all systems engaged in gathering produced gas from 
multiple wells, all EOR operations using CO2, and all 
petroleum and natural gas production located on islands, artificial 
islands or structures connected by a causeway to land, an island, or 
artificial island.
    (3) Onshore natural gas processing plants. Natural gas processing 
plants are designed to separate and recover natural gas liquids (NGLs) 
or other non-methane gases and liquids from a stream of produced 
natural gas to meet onshore natural gas transmission pipeline quality 
specifications through equipment performing one or more of the 
following processes: oil and condensate removal, water removal, 
separation of natural gas liquids, sulfur and carbon dioxide removal, 
fractionation of NGLs, or other processes, and also the capture of 
CO2 separated from natural gas streams for delivery outside 
the facility. In addition, field gathering and/or boosting stations 
that gather and process natural gas from multiple wellheads, and 
compress and transport natural gas (including but not limited to 
flowlines or intra-facility gathering lines or compressors) as feed to 
the natural gas processing plants are considered a part of the 
processing plant. Gathering and boosting stations that send the natural 
gas to an onshore natural gas transmission compression facility, or 
natural gas distribution facility, or to an end user are considered 
stand alone natural gas processing facilities. All residue gas 
compression equipment operated by a processing plant, whether inside or 
outside the processing plant fence, are considered part of natural gas 
processing plant.
    (4) Onshore natural gas transmission compression. Onshore natural 
gas transmission compression means any fixed combination of compressors 
that move natural gas at elevated pressure from production fields or 
natural gas processing facilities, in transmission pipelines, to 
natural gas distribution pipelines, or into storage. In addition, 
transmission compressor station includes equipment for liquids 
separation, natural gas dehydration, and tanks for the storage of water 
and hydrocarbon liquids.
    (5) Underground natural gas storage. Underground natural gas 
storage means subsurface storage, including but not limited to, 
depleted gas or oil reservoirs and salt dome caverns utilized for 
storing natural gas that has been transferred from its original 
location for the primary purpose of load balancing (the process of 
equalizing the receipt and delivery of natural gas); natural gas 
underground storage processes and operations (including, but not 
limited to, compression, dehydration and flow measurement); and all the 
wellheads connected to the compression units located at the facility.
    (6) Liquefied natural gas (LNG) storage. LNG storage means onshore 
LNG storage vessels located above ground, equipment for liquefying 
natural gas, compressors to capture and re-liquefy boil-off-gas, re-
condensers,

[[Page 18637]]

and vaporization units for re-gasification of the liquefied natural 
gas.
    (7) LNG import and export equipment. LNG import equipment means all 
onshore or offshore equipment that receives imported LNG via ocean 
transport, stores LNG, re-gasifies LNG, and delivers re-gasified 
natural gas to a natural gas transmission or distribution system. LNG 
export equipment means all onshore or offshore equipment that receives 
natural gas, liquefies natural gas, stores LNG, and transfers the LNG 
via ocean transportation to any location, including locations in the 
United States.
    (8) Natural Gas Distribution. Natural gas distribution means 
distribution pipelines (not interstate pipelines or intrastate 
pipelines) and metering and regulating stations, that physically 
deliver natural gas to end users.
    (b) [Reserved]


Sec.  98.231  Reporting threshold.

    (a) You must report GHG emissions from petroleum and natural gas 
systems if your facility as defined in Sec.  98.230 meets the 
requirements of Sec.  98.2(a)(2).
    (b) For applying the threshold defined in Sec.  98.2(a)(2), you 
must include combustion emissions from portable equipment that cannot 
move on roadways under its own power and drive train and that is 
stationed at a wellhead for more than 30 days in a reporting year, 
including drilling rigs, dehydrators, compressors, electrical 
generators, steam boilers, and heaters.


Sec.  98.232  GHGs to report.

    (a) You must report CO2 and CH4 emissions 
from each industry segment specified in paragraph (b) through (i) of 
this section.
    (b) For offshore petroleum and natural gas production, report 
emissions from all ``stationary fugitive'' and ``stationary vented'' 
sources as identified in the Minerals Management Service (MMS) Gulfwide 
Offshore Activity Data System (GOADS) study (2005 Gulfwide Emission 
Inventory Study MMS 2007-067).
    (c) For onshore petroleum and natural gas production, report 
emissions from the following source types:
    (1) Natural gas pneumatic high bleed device venting.
    (2) Natural gas pneumatic low bleed device venting.
    (3) Natural gas driven pneumatic pump venting.
    (4) Well venting for liquids unloading.
    (5) Gas well venting during conventional well completions.
    (6) Gas well venting during unconventional well completions.
    (7) Gas well venting during conventional well workovers.
    (8) Gas well venting during unconventional well workovers.
    (9) Gathering pipeline fugitives.
    (10) Storage tanks.
    (11) Reciprocating compressor rod packing venting.
    (12) Well testing venting and flaring.
    (13) Associated gas venting and flaring.
    (14) Dehydrator vent stacks.
    (15) Coal bed methane produced water emissions.
    (16) EOR injection pump blowdown.
    (17) Acid gas removal vent stack.
    (18) Hydrocarbon liquids dissolved CO2.
    (19) Centrifugal compressor wet seal degassing venting.
    (20) Produced water dissolved CO2.
    (21) Fugitive emissions from valves, connectors, open ended lines, 
pressure relief valves, compressor starter gas vents, pumps, flanges, 
and other fugitive sources (such as instruments, loading arms, pressure 
relief valves, stuffing boxes, compressor seals, dump lever arms, and 
breather caps for crude services).
    (d) For onshore natural gas processing, report emissions from the 
following sources:
    (1) Reciprocating compressor rod packing venting.
    (2) Centrifugal compressor wet seal degassing venting.
    (3) Storage tanks.
    (4) Blowdown vent stacks.
    (5) Dehydrator vent stacks.
    (6) Acid gas removal vent stack.
    (7) Flare stacks.
    (8) Gathering pipeline fugitives.
    (9) Fugitive emissions from: valves, connectors, open ended lines, 
pressure relief valves, meters, and centrifugal compressor dry seals.
    (e) For onshore natural gas transmission compression, report 
emissions from the following sources:
    (1) Reciprocating compressor rod packing venting.
    (2) Centrifugal compressor wet seal degassing venting.
    (3) Transmission storage tanks.
    (4) Blowdown vent stacks.
    (5) Natural gas pneumatic high bleed device venting.
    (6) Natural gas pneumatic low bleed device venting.
    (7) Fugitive emissions from connectors, block valves, control 
valves, compressor blowdown valves, pressure relief valves, orifice 
meters, other meters, regulators, and open ended lines.
    (f) For underground natural gas storage, report emissions from the 
following sources:
    (1) Reciprocating compressor rod packing venting.
    (2) Centrifugal compressor wet seal degassing venting.
    (3) Natural gas pneumatic high bleed device venting.
    (4) Natural gas pneumatic low bleed device venting.
    (5) Fugitive emissions from connectors, block valves, control 
valves, compressor blowdown valves, pressure relief valves, orifice 
meters, other meters, regulators, and open ended lines.
    (g) For LNG storage, report emissions from the following sources:
    (1) Reciprocating compressor rod packing venting.
    (2) Centrifugal compressor wet seal degassing venting.
    (3) Fugitive emissions from valves; pump seals; connectors; vapor 
recovery compressors, and other fugitive sources.
    (h) LNG import and export equipment, report emissions from the 
following sources:
    (1) Reciprocating compressor rod packing venting.
    (2) Centrifugal compressor wet seal degassing venting.
    (3) Blowdown vent stacks.
    (4) Fugitive emissions from valves, pump seals, connectors, vapor 
recovery compressors, and other fugitive sources.
    (i) For natural gas distribution, report emissions from the 
following sources:
    (1) Above ground meter regulators and gate station fugitive 
emissions from connectors, block valves, control valves, pressure 
relief valves, orifice meters, other meters, regulators, and open ended 
lines.
    (2) Below ground meter regulators and vault fugitives.
    (3) Pipeline main fugitives.
    (4) Service line fugitives.
    (j) You must report the CO2, CH4, and 
N2O emissions from each flare.
    (k) You must report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the emissions of CO2, 
CH4, and N2O from each stationary fuel combustion 
unit by following the requirements of subpart C.
    (l) You must report under subpart PP of this part (Suppliers of 
Carbon Dioxide), CO2 emissions captured and transferred off 
site by following the requirements of subpart PP.


Sec.  98.233  Calculating GHG emissions.

    (a) Natural gas pneumatic high bleed device venting. Calculate 
emissions from a natural gas pneumatic high bleed flow control device 
venting as follows:
    (1) Calculate vented emissions using manufacturer data.
    (i) Obtain from the manufacturer specific pneumatic device model 
natural gas bleed rate during normal operation.

[[Page 18638]]

    (ii) Calculate the natural gas emissions for each continuous bleed 
device using Equation W-1 of this section.

[GRAPHIC] [TIFF OMITTED] TP12AP10.082


Where:
Es,n = Annual natural gas emissions at standard 
conditions, in cubic feet.
Bs = Natural gas driven pneumatic device bleed rate 
volume at standard conditions in cubic feet per minute, as provided 
by the manufacturer.
T = Amount of time in minutes that the pneumatic device has been 
operational through the reporting period.

    (iii) Both CH4 and CO2 volumetric and mass 
emissions shall be calculated from volumetric natural gas emissions 
using calculations in paragraphs (u) and (v) of this section.
    (2) If manufacturer data for a specific device is not available, 
then use data for a similar device model, size and operational 
characteristics to estimate emissions.
    (b) Natural gas pneumatic low bleed device venting. Calculate 
emissions from natural gas pneumatic low continuous bleed device 
venting using Equation W-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.000

Where:

Masss,i = Annual total mass GHG emissions in metric tons 
per year at standard conditions from all natural gas pneumatic low 
bleed device venting, for GHG i.
Count = Total number of natural gas pneumatic low bleed devices.
EF = Population emission factors for natural gas pneumatic low bleed 
device venting listed in Tables W-1, W-3, and W-4 of this subpart 
for onshore petroleum and natural gas production, onshore natural 
gas transmission, and underground natural gas storage facilities, 
respectively.
GHG i = For onshore petroleum and natural gas production facilities, 
concentration of GHG i, CH4 or CO2, in 
produced natural gas; for facilities listed in Sec.  98.230(a)(3) 
through (a)(8), GHGi equals 1.
Convi = Conversion from standard cubic feet to metric tons 
CO2e; 0.000404 for CH4, and 0.00005189 for 
CO2.
24 * 365 = Conversion to yearly emissions estimate.

    (c) Natural gas driven pneumatic pump venting. Calculate emissions 
from natural gas driven pneumatic pump venting as follows:
    (1) Calculate emissions using manufacturer data.
    (i) Obtain from the manufacturer specific pump model natural gas 
emission (or manufacturer ``gas consumption'') per unit volume of 
liquid circulation rate at pump speeds and operating pressures.
    (ii) Maintain a log of the amount of liquid pumped annually from 
individual pumps.
    (iii) Calculate the natural gas emissions for each pump using 
Equation W-3 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.001

Where:

    Es,n = Annual natural gas emissions at standard 
conditions in cubic feet per year.
    Fs = Natural gas driven pneumatic pump gas emission 
in ``emission per volume of liquid pumped at operating pressure'' in 
scf/gallon at standard conditions, as provided by the manufacturer.
    V = Volume of liquid pumped annually in gallons/year.

    (iv) Both CH4 and CO2 volumetric and mass 
emissions shall be calculated from volumetric natural gas emissions 
using calculations in paragraphs (u) and (v) of this section.
    (2) If manufacturer data for a specific pump in Equation W-3 is not 
available, then use data for a similar pump model, size and operational 
characteristics to estimate emissions.
    (d) Acid gas removal (AGR) vent stacks. For AGR (including but not 
limited to processes such as amine, membrane, molecular sieve or other 
absorbents and adsorbents), calculate emissions for CO2 only 
(not CH4) using Equation W-4 of this section.

[GRAPHIC] [TIFF OMITTED] TP12AP10.002

Where:

Ea,CO2 = Annual volumetric CO2 emissions at 
ambient condition, in cubic feet per year.
V1 = Metered total annual volume of natural gas flow into 
AGR unit in cubic feet per year at ambient condition.
%Vol1 = Volume weighted CO2 content of natural 
gas into the AGR unit.
V2 = Metered total annual volume of natural gas flow out 
of the AGR unit in cubic feet per year at ambient condition.
%Vol2 = Volume weighted CO2 content of natural 
gas out of the AGR unit.

    (1) If a continuous gas analyzer is installed, then the continuous 
gas analyzer results must be used. If continuous gas analyzer is not 
available, quarterly gas samples must be taken to determine 
%Vol1 and %Vol2 according to methods set forth in 
Sec.  98.234(b).
    (2) Calculate CO2 volumetric emissions at standard 
conditions using calculations in paragraph (t) of this section.
    (3) Mass CO2 emissions shall be calculated from 
volumetric CO2 emissions using calculations in paragraphs 
(u) and (v) of this section.
    (e) Dehydrator vent stacks. For dehydrator vent stacks without 
vapor recovery or thermal control devices, calculate annual mass 
CH4 and CO2 emissions at standard temperature and 
pressure (STP) conditions using the simulation software package GRI-
GLYCalc Version 4.0 (incorporated by reference, see Sec.  98.7).
    (1) A minimum of the following parameters must be used for 
characterizing emissions from dehydrators:
    (i) Feed natural gas flow rate.
    (ii) Feed natural gas water content.
    (iii) Outlet natural gas water content.
    (iv) Absorbent circulation pump type (natural gas pneumatic/air 
pneumatic/electric).
    (v) Absorbent circulation rate.
    (vi) Absorbent type: Including, but not limited to, triethylene 
glycol (TEG), diethylene glycol (DEG) or ethylene glycol (EG).
    (vii) Use of stripping natural gas.
    (viii) Use of flash tank separator (and disposition of recovered 
gas).
    (ix) Hours operated.
    (x) Wet natural gas temperature, pressure, and composition.
    (2) Calculate annual emissions from dehydrator vent stacks to 
flares or regenerator fire-box/fire tubes as follows:
    (i) Use the dehydrator vent stack volume and gas composition as 
determined in paragraph (e)(1) of this section.

[[Page 18639]]

    (ii) Use the calculation methodology of flare stacks in paragraph 
(n) of this section to determine dehydrator vent stack emissions from 
the flare or regenerator combustion gas vent.
    (3) Dehydrators that use desiccant shall calculate emissions from 
the amount of gas vented from the vessel every time it is depressurized 
for the desiccant refilling process using Equation W-5 of this section.

[GRAPHIC] [TIFF OMITTED] TP12AP10.003


Where:

Es,n = Annual natural gas emissions at standard 
conditions.
H = Height of the dehydrator vessel (ft).
D = Inside diameter of the vessel (ft).
P1 = Atmospheric pressure (psia).
P2 = Pressure of the gas (psia).
P = pi (3.14).
%G = Percent of packed vessel volume that is gas.
T = Time between refilling (days).

    (i) Both CH4 and CO2 volumetric and mass 
emissions shall be calculated from volumetric natural gas emissions 
using calculations in paragraphs (u) and (v) of this section.
    (f) Well venting for liquids unloadings.
    (1) The emissions for well venting for liquids unloading shall be 
determined using either of the calculation methodologies described in 
paragraph (f)(1) of this section. The same calculation methodology must 
be used for the entire volume for the reporting year.
    (i) Calculation Methodology 1. For each unique well tubing diameter 
and producing horizon/formation combination in each gas producing field 
where gas wells are vented to the atmosphere to expel liquids 
accumulated in the tubing, a recording flow meter shall be installed on 
the vent line used to vent gas from the well (e.g., on the vent line 
off the wellhead separator or atmospheric storage tank) according to 
methods set forth in Sec.  98.234(b). Calculate emissions from well 
venting for liquids unloading using Equation W-6 of this section.

[GRAPHIC] [TIFF OMITTED] TP12AP10.004


Where:

Ea,n = Annual natural gas emissions at ambient conditions 
in cubic feet.
T = Cumulative amount of time in hours of well venting during the 
year.
FR = Flow Rate in cubic feet per hour, under ambient conditions as 
required in paragraph (f)(1)(i)(A), (f)(1)(i)(B) and (f)(1)(i)(C) of 
this section.

    Calculate natural gas volumetric emissions at standard conditions 
using calculations in paragraph (t) of this section. Both 
CH4 and CO2 volumetric and mass emissions shall 
be calculated from volumetric natural gas emissions using calculations 
in paragraphs (u) and (v) of this section.
    (A) The average flow rate per minute of venting is calculated for 
each unique tubing diameter and producing horizon/formation combination 
in each producing field.
    (B) This factor is applied to all wells in the field that have the 
same tubing diameter and producing horizon/formation combination, 
multiplied by the number of minutes of venting from all wells of the 
same tubing diameter and producing horizon/formation combination in 
that field.
    (C) A new emission factor is calculated every other year for each 
reporting field and horizon.
    (ii) Calculation Methodology 2. Calculate emissions from each well 
venting for liquids unloading using Equation W-7 of this section.

[GRAPHIC] [TIFF OMITTED] TP12AP10.005

Where:

Es,n = Annual natural gas emissions at standard 
conditions, in cubic feet/year.
0.37 x 10-3 = {pi(3.14)/4{time} /{(14.7*144) psia 
converted to pounds per square feet{time} 
CD = Casing diameter (inches).
WD = Well depth (feet).
SP = Shut-in pressure (psig).
V = Number of vents per year.
SFR = Sales flow rate of gas well in cubic feet per hour.
HR = Hours that the well was left open to the atmosphere during 
unloading.

    (A) Both CH4 and CO2 volumetric and mass 
emissions shall be calculated from volumetric natural gas emissions 
using calculations in paragraphs (u) and (v) of this section.
    (B) [Reserved]
    (g) Gas well venting during unconventional well completions and 
workovers. Calculate emissions from gas unconventional well venting 
during well completions and workovers from hydraulic fracturing using 
Equation W-8 of this section. Calculate natural gas volumetric 
emissions at standard conditions using calculations in paragraph (t) of 
this section. Both CH4 and CO2 volumetric and 
mass emissions shall be calculated from volumetric natural gas 
emissions using calculations in paragraphs (u) and (v) of this section.

[GRAPHIC] [TIFF OMITTED] TP12AP10.006

Where:
Ea,n = Annual natural gas vented emissions at ambient 
conditions in cubic feet.
T = Cumulative amount of time in hours of well venting during the 
year.
FR = Flow Rate in cubic feet per hour, under ambient conditions, as 
required in paragraph (g)(1) of this section.

    (1) The flow rate for gas well venting during well completions and 
workovers from hydraulic fracturing shall be determined using either of 
the calculation methodologies described in this paragraph (g)(1). The 
same calculation methodology must be used for the entire volume for the 
reporting year.
    (i) Calculation methodology 1. For one well completion in each gas 
producing field and for one well workover in each gas producing field, 
a recording flow meter shall be installed on the vent line during each 
well unloading event according to methods set forth in Sec.  98.234(b).
    (A) The average flow rate in cubic feet per minute of venting is 
calculated for one well completion in each field and for one well 
workover in each field.
    (B) The respective flow rates are applied to all well completions 
in the field and to all well workovers in the field, multiplied by the 
number of minutes of venting of all well completions and workovers, 
respectively, in that field.

[[Page 18640]]

    (C) New flow rates for completions and workovers are calculated 
every other year for each reporting field and horizon.
    (ii) Calculation Methodology 2. For one well completion in each gas 
producing field and for one well workover in each gas producing field, 
record the pressures measured before and after the well choke according 
to methods set forth in Sec.  98.234(b).
    (A) The average flow rate in cubic feet per minute of venting 
across the choke is calculated for one well completion in each field 
and for one well workover in each field.
    (B) The respective flow rates are applied to all well completions 
in the field and to all well workovers in the field, multiplied by the 
number of minutes of venting of all well completions and workovers in 
that field.
    (C) New flow rates for completions and workovers are calculated 
every other year for each reporting field and horizon.
    (iii) Calculate natural gas volumetric emissions at standard 
conditions using calculations in paragraph (t) of this section.
    (iv) Both CH4 and CO2 volumetric and mass 
emissions shall be calculated from volumetric natural gas emissions 
using calculations in paragraphs (u) and (v) of this section.
    (2) Calculate annual emissions from gas well venting during well 
completions and workovers to flares as follows:
    (i) Use the gas well venting volume during well completions and 
workovers as determined in paragraph (g)(1) of this section.
    (ii) Use the calculation methodology of flare stacks in paragraph 
(n) of this section to determine gas well venting during well 
completions and workovers emissions from the flare.
    (h) Gas well venting during conventional well completions and 
workovers. Calculate emissions from each gas well venting during 
conventional well completions and workovers using Equation W-9 of this 
section:
[GRAPHIC] [TIFF OMITTED] TP12AP10.007


    Where:

Ea,n = Annual emissions in cubic feet at ambient 
conditions from gas well venting during conventional well 
completions or workovers.
V = Daily gas production rate in cubic feet per minute.
T = Cumulative amount of time of well venting in minutes during the 
year.

    (i) Calculate natural gas volumetric emissions at standard 
conditions using calculations in paragraph (t) of this section.
    (ii) Both CH4 and CO2 volumetric and mass 
emissions shall be calculated from volumetric natural gas emissions 
using calculations in paragraphs (u) and (v) of this section.
    (iii) Blowdown vent stacks. Calculate blowdown vent stack emissions 
as follows:
    (1) Calculate the total volume (including, but not limited to, 
pipelines, compressor case or cylinders, manifolds, suction and 
discharge bottles and vessels) between isolation valves.
    (2) Retain logs of the number of blowdowns for each equipment type.
    (3) Calculate the total annual venting emissions using Equation W-
10 of this section:
[GRAPHIC] [TIFF OMITTED] TP12AP10.008


Where:

Ea,n = Annual natural gas venting emissions at ambient 
conditions from blowdowns in cubic feet.
N = Number of blowdowns for the equipment in reporting year.
Vv = Total volume of blowdown equipment chambers 
(including, but not limited to, pipelines, compressors and vessels) 
between isolation valves in cubic feet.

    (4) Calculate natural gas volumetric emissions at standard 
conditions using calculations in paragraph (t) of this section.
    (5) Calculate both CH4 and CO2 volumetric and 
mass emissions from volumetric natural gas emissions using calculations 
in paragraphs (u) and (v) of this section.
    (j) Onshore production and processing storage tanks. For emissions 
from atmospheric pressure storage tanks receiving produced liquids from 
onshore petroleum and natural gas production facilities (including 
stationary liquid storage not owned or operated by the reporter) and 
onshore natural gas processing facilities, calculate annual 
CH4 and CO2 emissions using the latest software 
package for E&P Tank (incorporated by reference, see Sec.  98.7).
    (1) A minimum of the following parameters must be used to 
characterize emissions from liquid transfer to atmospheric pressure 
storage tanks.
    (i) Separator oil composition.
    (ii) Separator temperature.
    (iii) Separator pressure.
    (iv) Sales oil API gravity.
    (v) Sales oil production rate.
    (vi) Sales oil Reid vapor pressure.
    (vii) Ambient air temperature.
    (viii) Ambient air pressure.
    (2) Determine if the storage tank has vapor recovery or thermal 
control devices.
    (i) Adjust the emissions estimated using E&P Tank (incorporated by 
reference, see Sec.  98.7) downward by the magnitude of emissions 
captured using a vapor recovery system for beneficial use.
    (ii) [Reserved]
    (3) Calculate emissions from liquids sent to atmospheric storage 
tanks vented to flares as follows:
    (i) Use the storage tank emissions volume and gas composition as 
determined in this section.
    (ii) Use the calculation methodology of flare stacks in paragraph 
(n) of this section to determine storage tank emissions from the flare.
    (4) If liquids are sent to atmospheric storage tanks where the tank 
emissions are not represented by the equilibrium conditions of the 
liquid in a gas-liquid separator and calculated by E&P Tank 
(incorporate by reference, see Sec.  98.7), then emissions shall be 
calculated as follows:
    (i) Use the storage tank emissions as determined in this section.
    (ii) Multiply the emissions by 3.87 for sales oil less than 45 API 
gravity.
    (iii) Multiply the emissions by 5.37 for sales oil equal to or 
greater than 45 API gravity.
    (k) Transmission storage tanks. For storage tanks without vapor 
recovery or thermal control devices in onshore natural gas transmission 
compression facilities calculate annual emissions as follows:
    (1) Monitor tank vapor vent stack for emissions using an optical 
gas imaging instrument according to methods set forth in Sec.  
98.234(a)(1) for a duration of 5 minutes.
    (2) If the tank vapors are continuous then use a meter to measure 
tank vapors.
    (i) Use a meter, such as, but not limited to a turbine meter, to 
estimate tank vapor volumes according to methods set forth in Sec.  
98.234(b).
    (ii) Use the appropriate gas composition in paragraph (u)(2)(iii) 
of this section.
    (3) Calculate emissions from storage tanks to flares as follows:
    (i) Use the storage tank emissions volume and gas composition as 
determined in paragraph (j)(1) of this section.
    (ii) Use the calculation methodology of flare stacks in paragraph 
(n) of this section to determine storage tank emissions from the flare.
    (l) Well testing venting and flaring. Calculate well testing 
venting and flaring emissions as follows:
    (1) Determine the gas to oil ratio (GOR) of the hydrocarbon 
production from each well tested.

[[Page 18641]]

    (i) If GOR is not available then use an appropriate standard method 
published by a consensus-based standards organization to determine GOR.
    (ii) [Reserved]
    (2) Estimate venting emissions using Equation W-11 of this section.
    [GRAPHIC] [TIFF OMITTED] TP12AP10.009
    

Where:

Ea,n = Annual volumetric natural gas emissions from well 
testing in cubic feet under ambient conditions.
GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil 
here refers to hydrocarbon liquids produced of all API gravities.
FR = Flow rate in barrels of oil per day for the well being tested.
D = Number of days during the year, the well is tested.

    (3) Calculate natural gas volumetric emissions at standard 
conditions using calculations in paragraph (t) of this section.
    (4) Calculate both CH4 and CO2 volumetric and 
mass emissions from volumetric natural gas emissions using calculations 
in paragraphs (u) and (v) of this section.
    (5) Calculate emissions from well testing to flares as follows:
    (i) Use the well testing emissions volume and gas composition as 
determined in paragraphs (l)(1) through (3) of this section.
    (ii) Use the calculation methodology of flare stacks in paragraph 
(n) of this section to determine well testing emissions from the flare.
    (m) Associated gas venting and flaring. Calculate associated gas 
venting and flaring emissions as follows:
    (1) Determine the GOR ratio of the hydrocarbon production from each 
well whose associated natural gas is vented or flared.
    (i) If GOR is not available then use an appropriate standard method 
published by a consensus-based standards organization to determine GOR.
    (i) [Reserved]
    (2) Estimate venting emissions using the Equation W-12 of this 
section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.010


Where:

Ea,n = Annual volumetric natural gas emissions from 
associated gas venting under ambient conditions, in cubic feet.
GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil 
here refers to hydrocarbon liquids produced of all API gravities.
V = Total volume of oil produced in barrels in the reporting year.

    (3) Calculate natural gas volumetric emissions at standard 
conditions using calculations in paragraph (t) of this section.
    (4) Calculate both CH4 and CO2 volumetric and 
mass emissions from volumetric natural gas emissions using calculations 
in paragraphs (u) and (v) of this section.
    (5) Calculate emissions from associated natural gas to flares as 
follows:
    (i) Use the associated natural gas volume and gas composition as 
determined in paragraphs (m)(1) through (3) of this section.
    (ii) Use the calculation methodology of flare stacks in paragraph 
(n) of this section to determine associated gas emissions from the 
flare.
    (n) Flare stacks. Calculate emissions from a flare stack as 
follows:
    (1) If you have a continuous flow measurement device on the flare, 
you must use the measured flow volumes to calculate the flare gas 
emissions. If you do not have a continuous flow measurement device on 
the flare, you can install a flow measuring device on the flare or use 
engineering calculations, company records, or similar estimates of 
volumetric flare gas flow.
    (2) If you have a continuous gas composition analyzer on gas to the 
flare, you must use these compositions in calculating emissions. If you 
do not have a continuous gas composition analyzer on gas to the flare, 
you must use the appropriate gas compositions for each stream of 
hydrocarbons going to the flare as follows:
    (i) When the stream going to the flare is natural gas, use the GHG 
mole percent in feed natural gas for all streams upstream of the de-
methanizer and GHG mole percent in facility specific residue gas to 
transmission pipeline systems for all emissions sources downstream of 
the de-methanizer overhead for onshore natural gas processing 
facilities.
    (ii) When the stream going to the flare is a hydrocarbon product 
stream, such as ethane or butane, then use a representative composition 
from the source for the stream.
    (3) Determine flare combustion efficiency from manufacturer. If not 
available, assume that flare combustion efficiency is 98 percent.
    (4) Calculate GHG volumetric emissions at actual conditions using 
Equations W-13, W-14, and W-15 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.011

[GRAPHIC] [TIFF OMITTED] TP12AP10.012

[GRAPHIC] [TIFF OMITTED] TP12AP10.013


Where:

Ea,i (un-combusted) = Contribution of annual uncombusted 
GHG i emissions from flare stack in cubic feet, under ambient 
conditions.
Ea,CO2 (combusted) = Contribution of annual emissions 
from combustion from flare stack in cubic feet, under ambient 
conditions.
Ea,I (total) = Total annual emissions from flare stack in 
cubic feet, under ambient conditions.
Va = Volume of natural gas sent to flare in cubic feet, 
during the year.
[eta] = Percent of natural gas combusted by flare (default is 98 
percent).
Xi = Concentration of GHG i in gas to the flare.
Yj = Concentration of natural gas hydrocarbon 
constituents j (such as methane, ethane, propane, butane, and 
pentanes plus).
Rj = Number of carbon atoms in the natural gas 
hydrocarbon constituent j; 1 for methane, 2 for ethane, 3 for 
propane, 4 for butane, and 5 for pentanes plus).

    (5) Calculate GHG volumetric emissions at standard conditions using 
calculations in paragraph (t) of this section.
    (6) Calculate both CH4 and CO2 mass emissions 
from volumetric CH4 and CO2 emissions using 
calculation in paragraph (v) of this section.

[[Page 18642]]

    (7) Calculate N2O emissions using the emission factors 
for Gas Flares listed in Table W-8 of this subpart.
    (8) This emissions source excludes any emissions calculated under 
other emissions sources in Sec.  98.233.
    (o) Centrifugal compressor wet seal degassing vents. Calculate 
emissions from centrifugal compressor wet seal degassing vents as 
follows:
    (1) For each centrifugal compressor determine the volume of vapors 
from wet seal oil degassing tank sent to an atmospheric vent or flare 
using a temporary or permanent flow measurement meter such as, but not 
limited to, a vane anemometer according to methods set forth in Sec.  
98.234(b).
    (2) Estimate annual emissions using meter flow measurement using 
Equation W-16 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.014


Where:

Ea,i = Annual GHG i (either CH4 or 
CO2) volumetric emissions at ambient conditions.
MT = Meter reading of gas emissions per unit time.
T = Total time the compressor associated with the wet seal(s) is 
operational in the reporting year.
Mi = Mole percent of GHG i in the degassing vent gas; use 
the appropriate gas compositions in paragraph (u)(2) of this 
section.
B = Percentage of centrifugal compressor wet seal degassing vent gas 
sent to vapor recovery or fuel gas or other beneficial use as 
determined by keeping logs of the number of operating hours for the 
vapor recovery system and the amount of vent gas that is directed to 
the fuel gas system.

    (3) Calculate CH4 and CO2 volumetric 
emissions at standard conditions using paragraph (t) of this section.
    (4) Calculate both CH4 and CO2 mass emissions 
from volumetric emissions using calculations in paragraph (v) of this 
section.
    (5) Calculate emissions from degassing vent vapors to flares as 
follows:
    (i) Use the degassing vent vapor volume and gas composition as 
determined in paragraphs (o)(1) through (3) of this section.
    (ii) Use the calculation methodology of flare stacks in paragraph 
(n) of this section to determine degassing vent vapor emissions from 
the flare.
    (p) Reciprocating compressor rod packing venting. Calculate annual 
CH4 and CO2 emissions from each reciprocating 
compressor rod packing venting as follows:
    (1) Estimate annual emissions using a meter flow measurement using 
Equation W-17 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.015


Where:

Ea,i = Annual GHG i (either CH4 or 
CO2) volumetric emissions at ambient conditions.
MT = Meter volumetric reading of gas emissions per unit time, under 
ambient conditions.
T = Total time the compressor associated with the venting is 
operational in the reporting year.
Mi = Mole percent of GHG i in the vent gas; use the 
appropriate gas compositions in paragraph (u)(2) of this section.

    (2) If the rod packing case is connected to an open ended vent line 
then use one of the following two methods to calculate emissions.
    (i) Measure emissions from all vents (including emissions 
manifolded to common vents) including rod packing, unit isolation 
valves, and blowdown valves using bagging according to methods set 
forth in Sec.  98.234(c).
    (ii) Use a temporary meter such as, but not limited to, a vane 
anemometer or a permanent meter such as, but not limited to, an orifice 
meter to measure emissions from all vents (including emissions 
manifolded to a common vent) including rod packing vents, unit 
isolation valves, and blowdown valves according to methods set forth in 
Sec.  98.234(b).
    (3) If the rod packing case is not equipped with a vent line use 
the following method to estimate emissions:
    (i) You must use the methods described in Sec.  98.234(a) to 
conduct annual leak detection of fugitive emissions from the packing 
case into an open distance piece, or from the compressor crank case 
breather cap or vent with a closed distance piece.
    (ii) Measure emissions using a high flow sampler, or calibrated 
bag, or appropriate meter according to methods set forth in Sec.  
98.234(d).
    (4) Conduct one measurement for each compressor in each of the 
operational modes that occurs during a reporting period:
    (i) Operating.
    (ii) Standby pressurized.
    (iii) Not operating, depressurized.
    (5) Calculate CH4 and CO2 volumetric 
emissions at standard conditions using calculations in paragraph (t) of 
this section.
    (6) Estimate CH4 and CO2 volumetric and mass 
emissions from volumetric natural gas emissions using the calculations 
in paragraphs (u) and (v) of this section.
    (q) Leak detection and leaker emission factors. You must use the 
methods described in Sec.  98.234(a) to conduct an annual leak 
detection of fugitive emissions from all sources listed in Sec.  
98.232(d)(9), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1). This 
paragraph (q) applies to emissions sources in streams with gas content 
greater than 10 percent CH4 plus CO2 by weight. 
Emissions sources in streams with gas content less than 10 percent 
CH4 plus CO2 by weight do not need to be 
reported. If fugitive emissions are detected for sources listed in this 
paragraph, calculate emissions using Equation W-18 of this section for 
each source with fugitive emissions.
[GRAPHIC] [TIFF OMITTED] TP12AP10.016


Where:

Es,i = Annual total volumetric GHG emissions at standard 
conditions from each fugitive source.
Count = Total number of this type of emission source found to be 
leaking.
EF = Leaker emission factor for specific sources listed in Table W-2 
through Table W-7 of this subpart.
GHGi = For onshore natural gas processing facilities, 
concentration of GHGi, CH4 or CO2, in the 
total hydrocarbon of the feed natural gas; for other facilities 
listed in Sec.  98.230(a)(3) through (a)(8), GHGi equals 
1.
T = Total time the specific source associated with the fugitive 
emission was operational in the reporting year, in hours.


[[Page 18643]]


    (1) Calculate GHG mass emissions in carbon dioxide equivalent at 
standard conditions using calculations in paragraph (v) of this 
section.
    (2) Onshore natural gas processing facilities shall use the 
appropriate default leaker emission factors listed in Table W-2 of this 
subpart for fugitive emissions detected from valves; connectors; open 
ended lines; pressure relief valves; meters; and centrifugal compressor 
dry seals.
    (3) Onshore natural gas transmission compression facilities shall 
use the appropriate default leaker emission factors listed in Table W-3 
of this subpart for fugitive emissions detected from connectors; block 
valves; control valves; compressor blowdown valves; pressure relief 
valves; orifice meters; other meters; regulators; and open ended lines.
    (4) Underground natural gas storage facilities for storage stations 
shall use the appropriate default leaker emission factors listed in 
Table W-4 of this subpart for fugitive emissions detected from 
connectors; block valves; control valves; compressor blowdown valves; 
pressure relief valves; orifice meters; other meters; regulators; and 
open ended lines.
    (5) LNG storage facilities shall use the appropriate default leaker 
emission factors listed in Table W-5 of this subpart for fugitive 
emissions detected from valves; pump seals; connectors; and other.
    (6) LNG import and export facilities shall use the appropriate 
default leaker emission factors listed in Table W-6 of this subpart for 
fugitive emissions detected from valves; pump seals; connectors; and 
other.
    (7) Natural gas distribution facilities for above ground meter 
regulator and gate stations shall use the appropriate default leaker 
emission factors listed in Table W-7 of this subpart for fugitive 
emissions detected from connectors; block valves; control valves; 
pressure relief valves; orifice meters; other meters; regulators; and 
open ended lines.
    (r) Population count and emission factors. This paragraph applies 
to emissions sources listed in Sec.  98.232(c)(2), (c)(9), (c)(15), 
(c)(21), (d)(8), (e)(6), (f)(4), (f)(5), (g)(3), (h)(4), (i)(2), (i)(3) 
and (i)(4), on 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. Calculate 
emissions from all sources listed in this paragraph using Equation W-19 
of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.017

    Where:Es,i = Annual total volumetric GHG emissions at 
standard conditions from each fugitive source.
    Count = Total number of this type of emission source at the 
facility.
    EF = Population emission factor for specific sources listed in 
Table W-1 through Table W-7 of this subpart.
    GHGi = for onshore petroleum and natural gas 
production facilities and onshore natural gas processing facilities, 
concentration of GHG i, CH4 or CO2, in 
produced natural gas or feed natural gas; for other facilities 
listed in Sec.  98.230 (b)(3) through (b)(8),GHGi equals 
1.
    T = Total time the specific source associated with the fugitive 
emission was operational in the reporting year, in hours.

    (1) Calculate both CH4 and CO2 mass emissions 
from volumetric emissions using calculations in paragraph (v) of this 
section.
    (2) Onshore petroleum and natural gas production facilities shall 
use the appropriate default population emission factors listed in Table 
W-1 of this subpart for fugitive emissions from valves; connectors; 
open ended lines; pressure relief valves; compressor starter gas vent; 
pump; flanges; other; and CBM well water production. Where facilities 
conduct EOR operations the emissions factor listed in Table W-1 shall 
be used to estimate all streams of gases, including recycle 
CO2 stream. In cases where the stream is almost all 
CO2, the emissions factors in Table W-1 shall be assumed to 
be for CO2 instead of natural gas.
    (3) Onshore natural gas processing facilities shall use the 
appropriate default population emission factor listed in Table W-2 of 
this subpart for fugitive emissions from gathering pipelines.
    (4) Underground natural gas storage facilities for storage 
wellheads shall use the appropriate default population emission factors 
listed in Table W-4 of this subpart for fugitive emissions from 
connectors; valves; pressure relief valves; and open ended lines.
    (5) LNG storage facilities shall use the appropriate default 
population emission factors listed in Table W-5 of this subpart for 
fugitive emissions from vapor recovery compressors.
    (6) LNG import and export facilities shall use the appropriate 
default population emission factor listed in Table W-6 of this subpart 
for fugitive emissions from vapor recovery compressors.
    (7) Natural gas distribution facilities shall use the appropriate 
default population emission factors listed in Table W-7 of this subpart 
for fugitive emissions from below grade M&R stations; gathering 
pipelines; mains; and services.
    (s) Offshore petroleum and natural gas production facilities in 
both state and federal waters. Report GHG emissions from all 
``stationary fugitive'' and ``stationary vented'' sources as identified 
in the Minerals Management Service (MMS) Gulfwide Offshore Activity 
Data System (GOADS) study (2005 Gulfwide Emission Inventory Study MMS 
2007-067) for each platform.
    (1) MMS GOADS Reporters. Offshore production facilities currently 
reporting under the MMS GOADS program will report the same annual 
emissions as calculated by GOADS under paragraph (s) of this section.
    (i) For the first reporting year, report the latest available 
emissions from GOADS.
    (ii) In subsequent reporting years when GOADS is updated reporters 
shall report the new emissions that are made available from the latest 
GOADS software.
    (ii) For each reporting year that does not overlap with the GOADS 
reporting year, report the last reported GOADS emissions with emissions 
adjusted based on the operating time for each platform.
    (iii) If MMS discontinues or delays their GOADS survey by more than 
4 years, then Platform operators shall collect monthly activity data 
every 4 years from platform sources in accordance with the latest 
version of the MMS GOADS program instructions, beginning in the year 
that the GOADS survey would have been conducted, and annual emissions 
shall be calculated using the latest available MMS GOADS emission 
factors and methods.
    (2) Non-MMS GOADS Reporters. Offshore production facilities not 
reporting under the MMS GOADS program shall collect monthly activity 
data from platform sources for the first reporting year in accordance 
with the latest MMS GOADS program instructions. Annual emissions shall 
be calculated using the latest MMS GOADS emission factors and methods.

[[Page 18644]]

    (i) In subsequent reporting years, facilities not reporting under 
GOADS shall follow the data collection cycle as GOADS in collecting new 
activity data monthly to estimate emissions and report emissions.
    (ii) For each reporting year that does not overlap with the GOADS 
reporting year, report the last reported emissions data with emissions 
adjusted based on the operating time for each platform.
    (iii) If MMS discontinues or delays their GOADS survey by more than 
4 years, then Platform operators shall collect monthly activity data 
every 4 years from platform sources in accordance with the latest 
version of the MMS GOADS program instructions, and annual emissions 
shall be calculated using currently available MMS GOADS emission 
factors and methods.
    (t) Volumetric emissions. Calculate volumetric emissions at 
standard conditions as specified in paragraphs (t)(1) or (2) of this 
section.
    (1) Calculate natural gas volumetric emissions at standard 
conditions by converting ambient temperature and pressure of natural 
gas emissions to standard temperature and pressure natural gas using 
Equation W-20 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.018


Where:

Es,n = Natural gas volumetric emissions at standard 
temperature and pressure (STP) conditions.
Ea,n = Natural gas volumetric emissions at ambient 
conditions.
Ts = Temperature at standard conditions. ([deg]F).
Ta = Temperature at actual emission conditions. ([deg]F).
Ps = Absolute pressure at standard conditions (inches of 
Hg).
Pa = Absolute pressure at ambient conditions (inches of 
Hg).

    (2) Calculate GHG volumetric emissions at standard conditions by 
converting ambient temperature and pressure of GHG emissions to 
standard temperature and pressure using Equation W-21 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.019


Where:

    Es,i = GHG i volumetric emissions at standard 
temperature and pressure (STP) conditions.
    Ea,i = GHG i volumetric emissions at actual 
conditions.
    Ts = Temperature at standard conditions. ([deg]F).
    Ta = Temperature at actual emission conditions. 
([deg]F).
    Ps = Absolute pressure at standard conditions (inches 
of Hg).
    Pa = Absolute pressure at ambient conditions (inches 
of Hg).

    (u) GHG volumetric emissions. Calculate GHG volumetric emissions at 
standard conditions as specified in paragraphs (u)(1) and (2) of this 
section.
    (1) Estimate CH4 and CO2 emissions from 
natural gas emissions using Equation W-22 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.020


Where:

Es,i = GHG i (either CH4 or CO2) 
volumetric emissions at standard conditions.
Es,n = Natural gas volumetric emissions at standard 
conditions.
Mi = Mole percent of GHG i in the natural gas.

    (2) For Equation W-22 of this section, the mole percent, 
Mi, shall be the annual average mole percent for each 
facility, as specified in paragraphs (u)(2)(i) through (vii) of this 
section.
    (i) GHG mole percent in produced natural gas for onshore petroleum 
and natural gas production facilities. If you have a continuous gas 
composition analyzer for produced natural gas, you must use these 
values in calculating emissions. If you do not have a continuous gas 
composition analyzer, then quarterly samples must be taken according to 
methods set forth in Sec.  98.234(b).
    (ii) GHG mole percent in feed natural gas for all emissions sources 
upstream of the de-methanizer and GHG mole percent in facility specific 
residue gas to transmission pipeline systems for all emissions sources 
downstream of the de-methanizer overhead for onshore natural gas 
processing facilities. If you have a continuous gas composition 
analyzer on feed natural gas, you must use these values in calculating 
emissions. If you do not have a continuous gas composition analyzer, 
then quarterly samples must be taken according to methods set forth in 
Sec.  98.234(b).
    (iii) GHG mole percent in transmission pipeline natural gas that 
passes through the facility for onshore natural gas transmission 
compression facilities.
    (iv) GHG mole percent in natural gas stored in underground natural 
gas storage facilities.
    (v) GHG mole percent in natural gas stored in LNG storage 
facilities.
    (vi) GHG mole percent in natural gas stored in LNG import and 
export facilities.
    (vii) GHG mole percent in local distribution pipeline natural gas 
that passes through the facility for natural gas distribution 
facilities.
    (v) GHG mass emissions. Calculate GHG mass emissions in carbon 
dioxide equivalent at standard conditions by converting the GHG 
volumetric emissions into mass emissions using Equation W-23 of this 
section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.021


Where:

Masss,i = GHG i (either CH4 or CO2) 
mass emissions at standard conditions in metric tons 
CO2e.
Es,i = GHG i (either CH4 or CO2) 
volumetric emissions at standard conditions, in cubic feet.
[rho]i = Density of GHG i, 0.053 kg/ft\3\ for 
CO2 and 0.0193 kg/ft\3\ for CH4.
GWP = Global warming potential, 1 for CO2 and 21 for 
CH4.

    (w) EOR injection pump blowdown. Calculate pump blowdown emissions 
as follows:
    (1) Calculate the total volume in cubic feet (including, but not 
limited to, pipelines, compressors and vessels) between isolation 
valves.
    (2) Retain logs of the number of blowdowns per reporting period.
    (3) Calculate the total annual venting emissions using Equation W-
24 of this section:
[GRAPHIC] [TIFF OMITTED] TP12AP10.022



[[Page 18645]]


Where:

Massc,i = Annual EOR injection gas venting emissions in 
metric tons at critical conditions ``c'' from blowdowns.
N = Number of blowdowns for the equipment in reporting year.
Vv = Total volume in cubic feet of blowdown equipment 
chambers (including, but not limited to, pipelines, compressors, 
manifolds and vessels) between isolation valves.
Rc = Density of critical phase EOR injection gas in kg/
ft\3\. Use an appropriate standard method published by a consensus-
based standards organization to determine density of super critical 
EOR injection gas.
GHGi = Mass fraction of GHGi in critical phase 
injection gas.

    (x) Hydrocarbon liquids dissolved CO2. Calculate 
dissolved CO2 in hydrocarbon liquids as follows:
    (1) Determine the amount of CO2 retained in hydrocarbon 
liquids after flashing in tankage at STP conditions. Quarterly samples 
must be taken according to methods set forth in Sec.  98.234(b) to 
determine retention of CO2 in hydrocarbon liquids 
immediately downstream of the storage tank. Use the average of the 
quarterly analysis for the reporting period.
    (2) Estimate emissions using Equation W-25 of this section.
    [GRAPHIC] [TIFF OMITTED] TP12AP10.023
    

Where:

Masss, CO2 = Annual CO2 emissions from 
CO2 retained in hydrocarbon liquids beyond tankage, in 
metric tons.
Shl = Amount of CO2 retained in hydrocarbon 
liquids in metric tons per barrel, under standard conditions.
Vhl = Total volume of hydrocarbon liquids produced in 
barrels in the reporting year.

    (y) Produced water dissolved CO2. Calculate dissolved 
CO2 in produced water as follows:
    (1) Determine the amount of CO2 retained in produced 
water at STP conditions. Quarterly samples must be taken according to 
methods set forth in Sec.  98.234(b) to determine retention of 
CO2 in produced water immediately downstream of the 
separator where hydrocarbon liquids and produced water are separated. 
Use the average of the quarterly analysis for the reporting period.
    (2) Estimate emissions using the Equation W-26 of this section.
    [GRAPHIC] [TIFF OMITTED] TP12AP10.024
    

Where:

Masss, CO2 = Annual CO2 emissions from 
CO2 retained in produced water beyond tankage, in metric 
tons.
Spw = Amount of CO2 retained in produced water 
in metric tons per barrel, under standard conditions.
Vpw = Total volume of produced water produced in barrels 
in the reporting year.

    (3) EOR operations that route produced water from separation 
directly to re-injection into the hydrocarbon reservoir in a closed 
loop system without any leakage to the atmosphere are exempt from 
paragraph (y) of this section.
    (z) Portable equipment combustion emissions. Calculate emissions 
from portable equipment using the Tier 1 methodology described in 
subpart C of this part (General Stationary Fuel Combustion Sources).


Sec.  98.234  Monitoring and QA/QC requirements.

    (a) You must use the method described as follows to conduct annual 
leak detection of fugitive emissions from all source types listed in 
Sec.  98.233(p)(3)(i) and (q) in operation or on standby mode that 
occur during a reporting period.
    (1) Optical gas imaging instrument. Use an optical gas imaging 
instrument for fugitive emissions detection in accordance with 40 CFR 
part 60, subpart A, Sec.  60.18(i)(1) and (2) Alternative work practice 
for monitoring equipment leaks. In addition, you must operate the 
optical gas imaging instrument to image the source types required by 
this proposed reporting rule in accordance with the instrument 
manufacturer's operating parameters.
    (2) [Reserved]
    (b) All flow meters, composition analyzers and pressure gauges that 
are used to provide data for the GHG emissions calculations shall use 
measurement methods, maintenance practices, and calibration methods, 
prior to the first reporting year and in each subsequent reporting year 
using an appropriate standard method published by a consensus standards 
organization such as, but not limited to, ASTM International, American 
National Standards Institute (ANSI), and American Petroleum Institute 
(API). If a consensus based standard is not available, you must use 
manufacturer instructions to calibrate the meters, analyzers, and 
pressure gauges.
    (c) Use calibrated bags (also known as vent bags) only where the 
emissions are at near-atmospheric pressures such that it is safe to 
handle and can capture all the emissions, below the maximum temperature 
specified by the vent bag manufacturer, and the entire emissions volume 
can be encompassed for measurement.
    (1) Hold the bag in place enclosing the emissions source to capture 
the entire emissions and record the time required for completely 
filling the bag. If the bag inflates in less than one second, assume 
one second inflation time.
    (2) Perform three measurements of the time required to fill the 
bag, report the emissions as the average of the three readings.
    (3) Estimate natural gas volumetric emissions at standard 
conditions using calculations in Sec.  98.233(t).
    (4) Estimate CH4 and CO2 volumetric and mass 
emissions from volumetric natural gas emissions using the calculations 
in Sec.  98.233(u) and (v).
    (d) Use a high volume sampler to measure emissions within the 
capacity of the instrument.
    (1) A technician following manufacturer instructions shall conduct 
measurements, including equipment manufacturer operating procedures and 
measurement methodologies relevant to using a high volume sampler, 
including, but not limited to, positioning the instrument for complete 
capture of the fugitive emissions without creating backpressure on the 
source.
    (2) If the high volume sampler, along with all attachments 
available from the manufacturer, is not able to capture all the 
emissions from the source then you shall use anti-static wraps or other 
aids to capture all emissions without violating operating requirements 
as provided in the instrument manufacturer's manual.
    (3) Estimate CH4 and CO2 volumetric and mass 
emissions from volumetric natural gas emissions using the calculations 
in Sec.  98.233(u) and (v).
    (4) Calibrate the instrument at 2.5 percent methane with 97.5 
percent air and 100 percent CH4 by using calibrated gas 
samples and by following manufacturer's instructions for calibration.


Sec.  98.235  Procedures for estimating missing data.

    A complete record of all estimated and/or measured parameters used 
in the GHG emissions calculations is required. If data are lost or an 
error occurs during annual emissions estimation or measurements, you 
must repeat the estimation or measurement activity for those sources as 
soon as possible, including in the subsequent reporting year if missing 
data are not discovered until after December 31 of the reporting year, 
until valid data for reporting is obtained. Data developed and/or 
collected in a subsequent reporting year to substitute for missing data 
cannot be used for that subsequent year's emissions estimation. Where 
missing

[[Page 18646]]

data procedures are used for the previous year, at least 30 days must 
separate emissions estimation or measurements for the previous year and 
emissions estimation or measurements for the current year of data 
collection.


Sec.  98.236  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain reported emissions as specified in this 
section.
    (a) Report annual emissions separately for each of the industry 
segment listed in paragraphs (a) (1) through (8) of this section. For 
each segment, report emissions from each source type in the aggregate, 
unless specified otherwise. For example, an underground natural gas 
storage operation with multiple reciprocating compressors must report 
emissions from all reciprocating compressors as an aggregate number.
    (1) Onshore petroleum and natural gas production.
    (2) Offshore petroleum and natural gas production.
    (3) Onshore natural gas processing.
    (4) Onshore natural gas transmission compression.
    (5) Underground natural gas storage.
    (6) LNG storage.
    (7) LNG import and export.
    (8) Natural gas distribution. Report each source in the aggregate 
for pipelines and for Metering and Regulating (M&R) stations.
    (b) Report emissions separately for standby equipment.
    (c) Report activity data for each aggregated source type as 
follows:
    (1) Count of natural gas pneumatic high bleed devices.
    (2) Count of natural gas pneumatic low bleed devices.
    (3) Count of natural gas driven pneumatic pumps.
    (4) For each acid gas removal unit report the following:
    (i) Total volume of natural gas flow into the acid gas removal 
unit.
    (ii) Total volume of natural gas flow out of the acid gas removal 
unit.
    (iii) Volume weighted CO2 content of natural gas into 
the acid gas removal unit.
    (5) For each dehydrator unit report the following:
    (i) Glycol dehydrators:
    (A) Glycol dehydrator feed natural gas flow rate.
    (B) Glycol dehydrator absorbent circulation pump type.
    (C) Glycol dehydrator absorbent circulation rate.
    (D) Whether stripper gas is used in glycol dehydrator.
    (E) Whether a flash tank separator is used in glycol dehydrator.
    (ii) Desiccant dehydrators:
    (A) The number of desiccant dehydrators operated.
    (B) [Reserved]
    (6) Count of wells vented to the atmosphere for liquids unloading 
for each field in the basin.
    (7) Count of wells venting during well completions for each field 
in the basin.
    (i) Number of conventional completions.
    (ii) Number of completions involving hydraulic fracturing.
    (8) Count of wells venting during well workovers for each field in 
the basin.
    (i) Number of conventional well workovers involving well venting to 
the atmosphere.
    (ii) Number of unconventional well workovers involving well venting 
to the atmosphere.
    (9) For each compressor blowdown vent stack report the following 
for each compressor:
    (i) Type of compressor whether reciprocating or centrifugal.
    (ii) Compressor capacity in horse powers.
    (iii) Volume of gas between isolation valves.
    (iv) Number of blowdowns per year.
    (10) For each estimate of gas emitted from liquids sent to 
atmospheric tank using E&P Tank report the following:
    (i) Immediate upstream separator temperature and pressure.
    (ii) Sales oil API gravity.
    (iii) Estimate of individual tank or tank battery capacity in 
barrels.
    (iv) Oil, hydrocarbon condensate and water sent to tank(s) in 
barrels.
    (v) Control measure: Either vapor recovery system or flaring of 
tank vapors.
    (11) For tank emissions identified using optical gas imaging 
instrument per Sec.  98.234(a), report the following for each tank:
    (i) Immediate upstream separator temperature and pressure.
    (ii) Sales oil API gravity.
    (iii) Tank capacity in barrels.
    (iv) Tank throughput in barrels.
    (v) Control measure: Either vapor recovery system or flaring of 
tank vapors.
    (vi) Optical gas imagining instrument used.
    (vii) Meter used for measuring emissions.
    (viii) List of emissions sources routed to the tank.
    (12) For well testing report the following for each field in the 
basin:
    (i) Number of wells tested in reporting period.
    (ii) Average gas to oil ratio for each field.
    (iii) Average flow rate during testing for each field.
    (iv) Average number of days the well is tested.
    (v) Whether the hydrocarbons produced during testing are vented or 
flared.
    (13) For associated natural gas venting report the following for 
each field in the basin:
    (i) Number of wells venting or flaring associated natural gas in 
reporting period.
    (ii) Average gas to oil ratio for each field.
    (iii) Average volume of oil produced per well per field.
    (iv) Whether the associated natural gas is vented or flared.
    (14) For flare stacks report the following for each flare:
    (i) Whether flare has a continuous flow monitor.
    (ii) If using engineering estimation methods, identify sources of 
emissions going to the flare.
    (iii) Whether flare has a continuous gas analyzer.
    (iv) Identify proportion of total natural gas to pure hydrocarbon 
stream being sent to the flare annually for the reporting period.
    (v) Flare combustion efficiency.
    (15) For well venting for liquids unloading report the following by 
field, basin, and well tubing size:
    (i) Number of wells being unloaded for liquids in reporting year.
    (ii) Average number of unloading(s) per well per reporting year.
    (iii) Average volume of natural gas produced per well per reporting 
year during liquids unloading.
    (16) For well completions and workovers report the following for 
each field in the basin:
    (i) Number of wells completed (worked over) in reporting year.
    (ii) Average number of days required for completion (workover).
    (iii) Average volume of natural gas produced per well per reporting 
year during well completion (workover).
    (17) For compressor wet seal degassing vents report the following 
for each degassing vent:
    (i) Number of wet seals connected to the degassing vent.
    (ii) Number of compressors whose wet seals are connected to the 
degassing vent.
    (iii) Total throughput of compressors whose wet seals are connected 
to the degassing vent.
    (iv) Type of meter used for making measurements.
    (v) Whether emissions estimate is based on a continuous or one time 
measurement.
    (vi) Total time the compressor(s) associated with the degassing 
vent stack

[[Page 18647]]

is operating. Sum the hours of operation if multiple compressors are 
connected to the vent stack.
    (vii) Proportion of vent gas recovered for fuel gas or sent to a 
flare.
    (18) For reciprocating compressor rod packing report the following 
per rod packing:
    (i) Total throughput of the reciprocating compressor whose rod 
packing emissions is being reported.
    (ii) Total time in hours the reciprocating compressor is in 
operating mode.
    (iii) Whether or not the rod packing case is connected to an open 
ended line.
    (iv) If rod packing is connected to an open ended line, report type 
of device used for measurement emissions.
    (v) If rod packing is not connected to an open ended vent line, 
report the locations from where the emissions from the rod packing are 
detected.
    (19) For fugitive emissions sources using emission factors for 
estimating emissions report the following:
    (i) Component count for each fugitive emissions source.
    (ii) CH4 and CO2 in produced natural gas for 
onshore petroleum and natural gas production.
    (20) For EOR injection pump blowdown report the following per pump:
    (i) Pump capacity.
    (ii) Volume of gas between isolation valves.
    (iii) Number of blowdowns per year.
    (iv) Supercritical phase EOR injection gas density.
    (21) For hydrocarbon liquids dissolved CO2 report the 
following for each field in the basin:
    (i) Volume of crude oil produced.
    (ii) [Reserved]
    (22) For produced water dissolved CO2 report the 
following for each field in the basin:
    (i) Volume of produced water produced.
    (ii) [Reserved]
    (d) Minimum, maximum and average throughput for each operation 
listed in paragraphs (a)(1) through (a)(8) of this section.
    (e) For offshore petroleum and natural gas production facilities, 
the number of connected wells, and whether the wells are producing oil, 
gas, or both.
    (f) Report emissions separately for portable equipment for the 
following source types: drilling rigs, dehydrators, compressors, 
electrical generators, steam boilers, and heaters.
    (1) Aggregate emissions by source type.
    (2) Report count of each source type.


Sec.  98.237  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must 
retain the following records:
    (a) Dates on which measurements were conducted.
    (b) Results of all emissions detected and measurements.
    (c) Calibration reports for detection and measurement instruments 
used.
    (d) Inputs and outputs of calculations or emissions computer model 
runs used for engineering estimation of emissions.


Sec.  98.238  Definitions.

    Except as provided below, all terms used in this subpart have the 
same meaning given in the Clean Air Act and subpart A of this part.
    Natural gas distribution facility means the distribution pipelines, 
metering stations, and regulating stations that are operated by a Local 
Distribution Company (LDC) that is regulated as a separate operating 
company by a public utility commission or that are operated as an 
independent municipally-owned distribution system.
    Offshore petroleum and natural gas production facility means each 
platform structure and all associated equipment as defined in paragraph 
(a)(1) of this section. All production equipment that is connected via 
causeways or walkways are one facility.
    Onshore petroleum and natural gas production facility means all 
petroleum or natural gas equipment associated with all petroleum or 
natural gas production wells under common ownership or common control 
by an onshore petroleum and natural gas production owner or operator 
located in a single hydrocarbon basin as defined by the American 
Association of Petroleum Geologists which is assigned a three digit 
Geologic Province Code. Where an operating entity holds more than one 
permit in a basin, then all onshore petroleum and natural gas 
production equipment relating to all permits in their name in the basin 
is one onshore petroleum and natural gas production facility.
    Separator means a vessel in which streams of multiple phases are 
gravity separated into individual streams of single phase.

 Table W-1 of Subpart W--Default Whole Gas Emission Factors for Onshore
                               Production
------------------------------------------------------------------------
                                                        Emission Factor
                  Onshore production                       (scf/hour/
                                                           component)
------------------------------------------------------------------------
Population Emission Factors--All Components, Gas
 Service
    Valve............................................               0.08
    Connector........................................               0.01
    Open-ended Line..................................               0.04
    Pressure Relief Valve............................               0.17
    Low-Bleed Pneumatic Device Vents.................               2.75
    Gathering Pipelines 1............................               2.81
    CBM Well Water Production 2......................               0.11
Population Emission Factors--All Components, Light
 Crude Service 3
    Valve............................................               0.04
    Connector........................................               0.01
    Open-ended Line..................................               0.04
    Pump.............................................               0.01
    Other 5..........................................               0.24
Population Emission Factors--All Components, Heavy
 Crude Service 4
    Valve............................................              0.001
    Flange...........................................              0.001
    Connector (other)................................             0.0004
    Open-ended Line..................................               0.01
    Other 5..........................................              0.003
------------------------------------------------------------------------
\1\ Emission Factor is in units of ``scf/hour/mile``.
\2\ Emission Factor is in units of ``scf methane/gallon``, in this case
  the operating factor is ``gallons/year'' and do not multiply by
  methane content.

[[Page 18648]]

 
\3\ Hydrocarbon liquids greater than or equal to 20*API are considered
  ``light crude``.
\4\ Hydrocarbon liquids less than 20*API are considered ``heavy crude``.
\5\ ``Others'' category includes instruments, loading arms, pressure
  relief valves, stuffing boxes, compressor seals, dump lever arms, and
  vents.


 Table W-2 of Subpart W--Default Total Hydrocarbon Emission Factors for
                               Processing
------------------------------------------------------------------------
                                       Before  de-         After  de-
                                        methanizer         methanizer
            Processing               emission factor    emission factor
                                        (scf/hour/         (scf/hour/
                                        component)         component)
------------------------------------------------------------------------
Leaker Emission Factors--Reciprocating Compressor Components, Gas
 Service
------------------------------------------------------------------------
Valve.............................              15.88              18.09
Connector.........................               4.31               9.10
Open-ended Line...................              17.90              10.29
Pressure Relief Valve.............               2.01              30.46
Meter.............................               0.02              48.29
------------------------------------------------------------------------
Leaker Emission Factors--Centrifugal Compressor Components, Gas Service
------------------------------------------------------------------------
Valve.............................               0.67               2.51
Connector.........................               2.33               3.14
Open-ended Line...................              17.90              16.17
Dry Seal..........................                105                105
------------------------------------------------------------------------
Leaker Emission Factors--Other Components, Gas Service
------------------------------------------------------------------------
Valve.............................                         6.42
Connector.........................                         5.71
Open-ended Line...................                        11.27
Pressure Relief Valve.............                         2.01
Meter.............................                         2.93
------------------------------------------------------------------------
Population Emission Factors--Other Components, Gas Service
------------------------------------------------------------------------
Gathering Pipelines \1\...........                        2.81
------------------------------------------------------------------------
\1\ Emission Factor is in units of ``scf/hour/mile''.


      Table W-3 of Subpart W--Default Methane Emission Factors for
                              Transmission
------------------------------------------------------------------------
                                                        Emission Factor
                     Transmission                          (scf/hour/
                                                           component)
------------------------------------------------------------------------
Leaker Emission Factors--All Components, Gas Service
------------------------------------------------------------------------
Connector............................................                2.7
Block Valve..........................................               10.4
Control Valve........................................                3.4
Compressor Blowdown Valve............................              543.5
Pressure Relief Valve................................               37.2
Orifice Meter........................................               14.3
Other Meter..........................................                0.1
Regulator............................................                9.8
Open-ended Line......................................               21.5
------------------------------------------------------------------------
Population Emission Factors--Other Components, Gas Service
------------------------------------------------------------------------
Low-Bleed Pneumatic Device Vents.....................               2.57
------------------------------------------------------------------------


Table W-4 of Subpart W--Default Methane Emission Factors for Underground
                                 Storage
------------------------------------------------------------------------
                                                        Emission Factor
                 Underground storage                       (scf/hour/
                                                           component)
------------------------------------------------------------------------
Leaker Emission Factors--Storage Station, Gas Service
------------------------------------------------------------------------
Connector............................................               0.96
Block Valve..........................................               2.02
Control Valve........................................               3.94
Compressor Blowdown Valve............................              66.15
Pressure Relief Valve................................              19.80
Orifice Meter........................................               0.46

[[Page 18649]]

 
Other Meter..........................................               0.01
Regulator............................................               1.03
Open-ended Line......................................               6.01
------------------------------------------------------------------------
Population Emission Factors--Storage Wellheads, Gas Service
------------------------------------------------------------------------
Connector............................................               0.01
Valve................................................               0.10
Pressure Relief Valve................................               0.17
Open-ended Line......................................               0.03
------------------------------------------------------------------------
Population Emission Factors--Other Components, Gas Service
------------------------------------------------------------------------
Low-Bleed Pneumatic Device Vents.....................               2.57
------------------------------------------------------------------------


 Table W-5 of Subpart W--Default Methane Emission Factors for Liquefied
                        Natural Gas (LNG) Storage
------------------------------------------------------------------------
                                                        Emission Factor
                     LNG storage                           (scf/hour/
                                                           component)
------------------------------------------------------------------------
Leaker Emission Factors--LNG Storage Components, LNG Service
------------------------------------------------------------------------
Valve................................................               1.19
Pump Seal............................................               4.00
Connector............................................               0.34
Other\1\.............................................               1.77
------------------------------------------------------------------------
Population Emission Factors--LNG Storage Compressor, Gas Service
------------------------------------------------------------------------
Vapor Recovery Compressor............................              6.81
------------------------------------------------------------------------
\1\ ``other'' equipment type should be applied for any equipment type
  other than connectors, pumps, or valves.


    Table W-6 of Subpart W--Default Methane Emission Factors for LNG
                                Terminals
------------------------------------------------------------------------
                                                        Emission Factor
                    LNG terminals                          (scf/hour/
                                                           component)
------------------------------------------------------------------------
Leaker Emission Factors--LNG Terminals Components, LNG Service
------------------------------------------------------------------------
Valve................................................               1.19
Pump Seal............................................               4.00
Connector............................................               0.34
Other................................................               1.77
------------------------------------------------------------------------
Population Emission Factors--LNG Terminals Compressor, Gas Service
------------------------------------------------------------------------
Vapor Recovery Compressor............................               6.81
------------------------------------------------------------------------


      Table W-7 of Subpart W--Default Methane Emission Factors for
                              Distribution
------------------------------------------------------------------------
                                                        Emission Factor
                     Distribution                          (scf/hour/
                                                           component)
------------------------------------------------------------------------
Leaker Emission Factors--Above Grade M&R Stations Components, Gas
 Service
------------------------------------------------------------------------
Connector............................................               1.69
Block Valve..........................................              0.557
Control Valve........................................               9.34
Pressure Relief Valve................................              0.270
Orifice Meter........................................              0.212
Regulator............................................              0.772
Open-ended Line......................................             26.131
------------------------------------------------------------------------
Population Emission Factors--Below Grade M&R Stations Components, Gas
 Service \1\
------------------------------------------------------------------------
Below Grade M&R Station, Inlet Pressure > 300 psig...               1.30

[[Page 18650]]

 
Below Grade M&R Station, Inlet Pressure 100 to 300                  0.20
 psig................................................
Below Grade M&R Station, Inlet Pressure < 100 psig...               0.10
------------------------------------------------------------------------
Population Emission Factors--Distribution Mains, Gas Service \2\
------------------------------------------------------------------------
Unprotected Steel....................................              12.58
Protected Steel......................................               0.35
Plastic..............................................               1.13
Cast Iron............................................              27.25
------------------------------------------------------------------------
Population Emission Factors--Distribution Services, Gas Service \2\
------------------------------------------------------------------------
Unprotected Steel....................................               0.19
Protected Steel......................................               0.02
Plastic..............................................              0.001
Copper...............................................              0.03
------------------------------------------------------------------------
\1\ Emission Factor is in units of ``scf/hour/station``
\2\ Emission Factor is in units of ``scf/hour/service``


 Table W-8 of Subpart W--Default Nitrous Oxide Emission Factors for Gas
                                 Flaring
------------------------------------------------------------------------
                                                        Emission Factor
                                                         (metric tons/
                     Gas Flaring                           MMscf gas
                                                         production or
                                                           receipts)
------------------------------------------------------------------------
Population Emission Factors--Gas Flaring
------------------------------------------------------------------------
Gas Production.......................................           5.90E-07
Sweet Gas Processing.................................           7.10E-07
Sour Gas Processing..................................           1.50E-06
Conventional Oil Production \1\......................           1.00E-04
Heavy Oil Production \2\.............................          7.30E-05
------------------------------------------------------------------------
\1\ Emission Factor is in units of ``metric tons/barrel conventional oil
  production``
\2\ Emission Factor is in units of ``metric tons/barrel heavy oil
  production``

[FR Doc. 2010-6767 Filed 4-9-10; 8:45 am]
BILLING CODE 6560-50-P