Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas Systems, 18608-18650 [2010-6767]

Agencies

• ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 75, Number 69 (Monday, April 12, 2010)]
[Proposed Rules]
[Pages 18608-18650]
From the Federal Register Online via the Government Printing 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: https://www.regulations.gov. 
Follow the online instructions for submitting comments.
     E-mail: GHG_Reporting_Rule_Oil_and_Natural_Gas@epa.gov. 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 
https://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 https://www.regulations.gov or e-mail. The https://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 https://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 https://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 https://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: GHGMRR@epa.gov. For technical information contact the 
Greenhouse Gas Reporting Rule Hotline at telephone number: (877) 444-
1188; or e-mail: GHGMRR@epa.gov. To obtain information about the public 
hearings or to register to speak at the hearings, please go to https://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: 
GHG_Reporting_Rule_Oil_and_Natural_Gas@epa.gov.
    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