[Federal Register Volume 75, Number 229 (Tuesday, November 30, 2010)]
[Rules and Regulations]
[Pages 74458-74515]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-28655]



[[Page 74457]]

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

Part III





Environmental Protection Agency





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



40 CFR Part 98



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

Federal Register / Vol. 75 , No. 229 / Tuesday, November 30, 2010 / 
Rules and Regulations

[[Page 74458]]


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

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 98

[EPA-HQ-OAR-2009-0923; FRL-9226-1]
RIN 2060-AP99


Mandatory Reporting of Greenhouse Gases: Petroleum and Natural 
Gas Systems

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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

SUMMARY: EPA is promulgating a regulation to require monitoring and 
reporting of greenhouse gas emissions from petroleum and natural gas 
systems. This action adds this source category to the list of source 
categories already required to report greenhouse gas emissions. This 
action applies to sources with carbon dioxide equivalent emissions 
above certain threshold levels as described in this regulation. This 
action does not require control of greenhouse gases.

DATES: The final rule is effective on December 30, 2010. The 
incorporation by reference of certain publications listed in the rule 
is approved by the Director of the Federal Register as of December 30, 
2010.

ADDRESSES: EPA established a single docket under Docket ID No. EPA-HQ-
OAR-2009-0923 for this action. All documents in the docket are listed 
on the http://www.regulations.gov Web site. Although listed in the 
index, some information is not publicly available, e.g., confidential 
business information (CBI) or other information whose disclosure is 
restricted by statute. Certain other material, such as copyrighted 
material, is not placed on the Internet and will be publicly available 
only in hard copy form. Publicly available docket materials are 
available either electronically through http://www.regulations.gov or 
in hard copy at EPA's Docket Center, Public Reading Room, EPA West 
Building, Room 3334, 1301 Constitution Avenue, 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) 566-1741.

FOR FURTHER INFORMATION CONTACT: Carole Cook, Climate Change Division, 
Office of Atmospheric Programs (MC-6207J), Environmental Protection 
Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone 
number: (202) 343-9263; fax number: (202) 343-2342; e-mail address: 
<a href="/cdn-cgi/l/email-protection#2c6b646b7e495c435e5845424b7e5940496c495c4d024b435a"><span class="__cf_email__" data-cfemail="ffb8b7b8ad9a8f908d8b969198ad8a939abf9a8f9ed1989089">[email protected]</span></a>. For technical information and implementation 
materials, please go to the Web site http://www.epa.gov/climatechange/emissions/ghgrulemaking.html. To submit a question, select Rule Help 
Center, followed by Contact Us.

SUPPLEMENTARY INFORMATION: 
    Regulated Entities. The Administrator determined that this action 
is subject to the provisions of Clean Air Act (CAA) section 307(d). See 
CAA section 307(d)(1)(V) (the provisions of section 307(d) apply to 
``such other actions as the Administrator may determine''). This final 
rule affects owners or operators of petroleum and natural gas systems. 
Regulated categories and entities may include those listed in Table 1 
of this preamble:

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

    Table 1 of this preamble is not intended to be exhaustive, but 
rather provides a guide for readers regarding facilities likely to be 
affected by this action. Although Table 1 of this preamble lists the 
types of facilities of which EPA is aware that could be potentially 
affected by this action, other types of facilities not listed in the 
table could also be subject to reporting requirements. To determine 
whether you are affected by this action, you should carefully examine 
the applicability criteria found in 40 CFR part 98, subpart A as 
amended by this action. 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 final rule have GHG 
emissions from multiple source categories listed in 40 CFR part 98. 
Table 2 of this preamble has been developed as a guide to help 
potential reporters in the petroleum and natural gas industry affected 
by this action identify other source categories (by subpart) that they 
may need to: (1) Consider in their facility applicability 
determination, and (2) include in their reporting. Table 2 of this 
preamble identifies the subparts that are likely to be relevant to 
sources with petroleum and natural gas systems. 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
------------------------------------------------------------------------
                                       Other subparts recommended for
          Source category             review to determine applicability
------------------------------------------------------------------------
Petroleum and Natural Gas Systems.  40 CFR part 98, subpart C: General
                                     Stationary Fuel Combustion Sources.
                                    40 CFR part 98, subpart Y: Petroleum
                                     Refineries.
                                    40 CFR part 98, subpart MM:
                                     Suppliers of Petroleum Products.
                                    40 CFR part 98, subpart NN:
                                     Suppliers of Natural Gas and
                                     Natural Gas Liquids.
                                    40 CFR part 98, subpart PP:
                                     Suppliers of Carbon Dioxide
                                    40 CFR part 98, subpart RR:
                                     Injection and Geologic
                                     Sequestration of Carbon Dioxide
                                     (proposed).
------------------------------------------------------------------------


[[Page 74459]]

    What is the effective date? The final rule is effective on December 
30, 2010. Section 553(d) of the Administrative Procedure Act (APA), 5 
U.S.C. Chapter 5, generally provides that rules may not take effect 
earlier than 30 days after they are published in the Federal Register. 
EPA is issuing this final rule under section 307(d)(1) of the Clean Air 
Act, which states: ``The provisions of section 553 through 557 * * * of 
Title 5 shall not, except as expressly provided in this section, apply 
to actions to which this subsection applies.'' Thus, section 553(d) of 
the APA does not apply to this rule. EPA is nevertheless acting 
consistently with the purposes underlying APA section 553(d) in making 
this rule effective on December 30, 2010. Section 5 U.S.C. 553(d)(3) 
allows an effective date less than 30 days after publication ``as 
otherwise provided by the agency for good cause found and published 
with the rule.'' As explained below, EPA finds that there is good cause 
for this rule to become effective on or before December 31, 2010, even 
if this results in an effective date fewer than 30 days from date of 
publication in the Federal Register.
    While this action is being signed prior to December 1, 2010, there 
is likely to be a significant delay in the publication of this rule as 
it contains complex diagrams, equations, and charts, and is relatively 
long in length. As an example, EPA signed a shorter technical 
amendments package related to the same underlying reporting rule on 
October 7, 2010, and it was not published until October 28, 2010, 75 FR 
66434, three weeks later.
    The purpose of the 30-day waiting period prescribed in 5 U.S.C. 
553(d) is to give affected parties a reasonable time to adjust their 
behavior and prepare before the final rule takes effect. Where, as 
here, the final rule will be signed and made available on the EPA Web 
site more than 30 days before the effective date, but where the 
publication is likely to be delayed due to the complexity and length of 
the rule, that purpose is still met. Moreover, for specified emission 
sources for certain industry segments, EPA has made available the 
optional use of best available monitoring methods (BAMM) during the 
2011 calendar year. For these circumstances, facilities covered by this 
rule may use BAMM for any parameter for which it is not reasonably 
feasible to acquire, install, or operate a required piece of monitoring 
equipment in a facility, or to procure measurement services from 
necessary providers. This will provide facilities a substantial 
additional period to adjust their behavior to the requirements of the 
final rule. Accordingly, we find good cause exists to make this rule 
effective on or before December 31, 2010, consistent with the purposes 
of 5 U.S.C. 553(d)(3).\1\
---------------------------------------------------------------------------

    \1\ We recognize that this rule could be published at least 30 
days before December 31, 2010, which would negate the need for this 
good cause finding, and we plan to request expedited publication of 
this rule in order to decrease the likelihood of a printing delay. 
However, as we cannot know the date of publication in advance of 
signing this rule, we are proceeding with this good cause finding 
for an effective date on or before December 31, 2010.
---------------------------------------------------------------------------

Judicial Review

    Under CAA section 307(b)(1), judicial review of this final rule is 
available only by filing a petition for review in the U.S. Court of 
Appeals for the District of Columbia Circuit by January 31, 2011. Under 
CAA section 307(d)(7)(B), only an objection to this final rule that was 
raised with reasonable specificity during the period for public comment 
can be raised during judicial review. This section also provides a 
mechanism for us to convene a proceeding for reconsideration, ``[i]f 
the person raising an objection can demonstrate to EPA that it was 
impracticable to raise such objection within [the period for public 
comment] or if the grounds for such objection arose after the period 
for public comment (but within the time specified for judicial review) 
and if such objection is of central relevance to the outcome of this 
rule.'' Any person seeking to make such a demonstration to us should 
submit a Petition for Reconsideration to the Office of the 
Administrator, Environmental Protection Agency, Room 3000, Ariel Rios 
Building, 1200 Pennsylvania Ave., NW., Washington, DC 20004, with a 
copy to the person listed in the preceding FOR FURTHER INFORMATION 
CONTACT section, and the Associate General Counsel for the Air and 
Radiation Law Office, Office of General Counsel (Mail Code 2344A), 
Environmental Protection Agency, 1200 Pennsylvania Ave., NW., 
Washington, DC 20004. Note, under CAA section 307(b)(2), the 
requirements established by this final rule may not be challenged 
separately in any civil or criminal proceedings brought by EPA to 
enforce these requirements.
    Acronyms and Abbreviations. The following acronyms and 
abbreviations are used in this document.

AAPG American Association of Petroleum Geologists
AGA American Gas Association
AGR Acid gas removal
ANSI American National Standards Institute
API American Petroleum Institute
ASME American Society of Mechanical Engineers
ASTM American Society for Testing and Materials
BLS Bureau of Labor Statistics
BOEMRE Bureau of Ocean Energy Management, Regulation and Enforcement
CAA Clean Air Act
CBI Confidential business information
CBM Coal bed methane
CEMS Continuous emission monitoring systems
cf cubic feet
CFR Code of Federal Regulations
CH<INF>4</INF> methane
CO<INF>2</INF> carbon dioxide
CO<INF>2</INF>e CO<INF>2</INF>-equivalent
DOE Department of Energy
E&P exploration and production
EIA Economic Impact Analysis
EO Executive Order
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
ESD emergency shutdown
FPSO floating production and storage offloading
FR Federal Register
GHG greenhouse gas
GOR gas to oil ratio
GRI Gas Research Institute
GWP global warming potential
HHV high heat value
IBR incorporation by reference
ICR information collection request
IPCC Intergovernmental Panel on Climate Change
IR infrared
ISO International Organization for Standardization
kg kilograms
LACT lease automatic custody transfer
LDCs local natural gas distribution companies
LNG liquefied natural gas
LPG liquefied petroleum gas
M&R meters and regulators
mmBtu million British thermal units
MMS Minerals Management Service
MMscfd million standard cubic feet per day
MMTCO<INF>2</INF>e million metric tons carbon dioxide equivalent
MRR mandatory GHG reporting rule
N<INF>2</INF>O nitrous oxide
NAESB North American Energy Standards Board
NAICS North American Industry Classification System
NGLs natural gas liquids
NTTAA National Technology Transfer and Advancement Act
OAQPS Office of Air Quality, Planning and Standards
OMB Office of Management and Budget
OVA organic vapor analyzer
ppm parts per million
QA quality assurance
QA/QC quality assurance/quality control
RFA Regulatory Flexibility Act
RGGI Regional Greenhouse Gas Initiative
RIA Regulatory Impact Analysis
SBA Small Business Administration
SBREFA Small Business Regulatory Enforcement and Fairness Act
SSM startup, shutdown, and malfunction
STP standard temperature and pressure
TCR The Climate Registry
TSD technical support document
TVA toxic vapor analyzer

[[Page 74460]]

U.S. United States
UMRA Unfunded Mandates Reform Act of 1995
U.S.C. United States Code
USGS United States Geologic Society
VOC volatile organic compound(s)
WCI Western Climate Initiative

Table of Contents

I. Background
    A. Organization of this Preamble
    B. Background on the Final Rule
    C. Legal Authority
II. Reporting Requirements for Petroleum and Natural Gas Systems
    A. Overview of Greenhouse Gas Reporting Program
    B. Overview of Confidentiality Determination for Data Elements 
in the Greenhouse Gas Reporting Program
    C. Summary of Changes to the General Provisions of the 
Greenhouse Gas Reporting Program
    D. Summary of the Requirements for Petroleum and Natural Gas 
Systems (Subpart W)
    E. Summary of Major Changes and Clarifications Since Proposal
    F. Summary of Comments and Responses
III. Economic Impacts of the Rule
    A. How were compliance costs estimated?
    B. What are the costs of the rule?
    C. What are the economic impacts of the rule?
    D. What are the Impacts of the Rule on Small Businesses?
    E. What are the Benefits of the Rule for Society?
IV. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act (UMRA)
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination with 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children from 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions that Significantly Affect 
Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions to Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. Congressional Review Act

I. Background

A. Organization of This Preamble

    This preamble consists of four sections. The first section provides 
a brief history of 40 CFR part 98 and describes the purpose and legal 
authority for this action.
    The second section of this preamble summarizes the revisions made 
to the general provisions in 40 CFR part 98, subpart A and outlines the 
specific requirements for subpart W being incorporated into 40 CFR part 
98 by this action. It also describes the major changes made to this 
source category since proposal and provides a brief summary of 
significant public comments and EPA's responses on issues specific to 
each industry segment. Additional responses to significant comments can 
be found in the document Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart W: Petroleum and Natural Gas 
Systems.
    The third section of this preamble provides the summary of the cost 
impacts, economic impacts, and benefits of the final rule and discusses 
comments on the economic impact analyses for subpart W.
    Finally, the last section discusses the various statutory and 
executive order requirements applicable to this rulemaking.

B. Background on the Final Rule

    This action finalizes monitoring and reporting requirements for 
petroleum and natural gas systems.
    On April 12, 2010, EPA proposed subpart W--Petroleum and Natural 
Gas Systems, amending 40 CFR part 98 (i.e., the regulatory requirements 
for the Greenhouse Gas Reporting Program). The GHG Reporting Program 
requires reporting of GHG emissions and other relevant information from 
certain source categories in the United States. The GHG Reporting 
Program, which became effective on December 29, 2009, includes 
reporting requirements for facilities and suppliers in 32 source 
categories. EPA established this program in response to the fiscal year 
2008 Consolidated Appropriations Act.\2\ This Act authorized funding 
for EPA to develop and publish a rule ``* * * to require the mandatory 
reporting of greenhouse gas emissions above appropriate thresholds in 
all sectors of the economy of the United States.'' An accompanying 
joint explanatory statement directed EPA to ``use its existing 
authority under the Clean Air Act'' to develop a mandatory GHG 
reporting rule. For more detailed background information on the GHG 
Reporting Program, see the preamble to the final rule establishing the 
GHG Reporting Program (74 FR 56260, October 30, 2009).
---------------------------------------------------------------------------

    \2\ Consolidated Appropriations Act, 2008, Public Law 110-161, 
121 Stat. 1844, 2128. Congress reaffirmed interest in a GHG 
reporting rule, and provided additional funding in the 2009 and 2010 
Appropriations Acts (Consolidated Appropriations Act, 2009, Pub. L. 
110-329, 122 Stat. 3574-3716 and Consolidated Appropriations Act, 
2010, Pub. L. 111-117, Stat. 3034-3408).
---------------------------------------------------------------------------

    This final action adds requirements for facilities that contain 
petroleum and natural gas systems to report equipment leaks and vented 
GHG emissions (subpart W) to the GHG Reporting Program. The 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 CO<INF>2</INF> equivalent per year. These data will inform EPA's 
implementation of CAA section 103(g) regarding improvements in sector 
based non-regulatory strategies and technologies for preventing or 
reducing air pollutants, and inform policy on possible regulatory 
actions to address GHG emissions. As stated earlier in this section, 
this rule was proposed by EPA on April 12, 2010. One public hearing was 
held in April 2010, and the 60-day public comment period ended June 11, 
2010.

C. Legal Authority

    EPA is promulgating 40 CFR part 98, subpart W under the existing 
CAA authorities provided in CAA section 114. As discussed in detail in 
Sections I.C and II.Q of the preamble to the 2009 final rule (74 FR 
56260), CAA section 114(a)(1) provides EPA with broad authority to 
require emissions sources, persons subject to the CAA, manufacturers of 
process or control equipment, or persons whom the Administrator 
believes may have necessary information to monitor and report emissions 
and provide such other information as the Administrator requests for 
the purposes of carrying out any provision of the CAA. EPA may gather 
information for a variety of purposes, including for the purpose of 
assisting in the development of emissions reduction regulations in the 
petroleum and natural gas industry, determining compliance with 
implementation plans or standards, or more broadly for ``carrying out 
any provision'' of the CAA. Section 103 of the CAA authorizes EPA to 
establish a national research and development program, including non-
regulatory approaches and technologies, for the prevention and control 
of air pollution, including GHGs. As discussed in the petroleum and 
natural gas systems proposal (75 FR 18608, April 12, 2010), among other 
things, data from petroleum and natural gas systems will inform 
decisions about possible emissions reduction regulations in the 
petroleum and natural gas industry. The data collected will also inform 
EPA's implementation of CAA section 103(g) regarding improvements in 
sector-based

[[Page 74461]]

non-regulatory strategies and technologies for preventing or reducing 
air pollutants.
    EPA has the authority under the CAA to collect emissions 
information from offshore petroleum and natural gas platforms including 
those located in areas of the Central and Western Gulf of Mexico as 
identified in CAA section 328(b). This final action 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 offshore platforms will 
inform our analyses, including options applicable to emissions of any 
offshore platforms that EPA is authorized to regulate under the CAA.

II. Reporting Requirements for Petroleum and Natural Gas Systems

A. Overview of Greenhouse Gas Reporting Program

    The GHG Reporting Program requires reporting of GHG emissions and 
other relevant information from certain source categories in the United 
States, as discussed in Section I.B. of this preamble. The rule 
requires annual reporting of GHGs including carbon dioxide 
(CO<INF>2</INF>), methane (CH<INF>4</INF>), nitrous oxide 
(N<INF>2</INF>O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), 
sulfur hexafluoride (SF<INF>6</INF>), and other fluorinated compounds 
(e.g., hydrofluoroethers (HFEs)).
    The GHG Reporting Program requires that source categories subject 
to 40 CFR part 98 monitor and report GHGs in accordance with the 
methods specified in the individual subparts. For a list of the 
specific GHGs to be reported and the GHG calculation procedures, 
monitoring, missing data procedures, recordkeeping, and reporting 
required by facilities subject to subpart W included in this action, 
see Section II.D of this preamble.

B. Overview of Confidentiality Determination for Data Elements in the 
Greenhouse Gas Reporting Program

    This final rule does not address whether data reported under 
subpart W will be released to the public or will be treated as 
confidential business information. EPA published a proposed rule and 
confidentiality determination on July 7, 2010 (75 FR 39094) that 
addressed this issue. In that action, EPA proposed which specific data 
elements would be released to the public and which would be treated as 
confidential business information. EPA received comments on the 
proposal, and is in the process of considering these comments. A final 
rule and determination will be issued before any data are released, and 
the final determination will include all of the data elements under 
subpart W.

C. Summary of Changes to the General Provisions of the Greenhouse Gas 
Reporting Program

    This final action amends certain requirements in 40 CFR part 98, 
subpart A (General Provisions). These amendments are summarized in this 
section of the preamble.
    Changes to Applicability. In this final action, EPA is amending 
Table A-4 of subpart A, referenced in 40 CFR 98.2(a)(2), to add the 
petroleum and natural gas systems source category. In addition, EPA is 
amending 40 CFR 98.2(a) so that 40 CFR part 98 applies to facilities 
located in the United States and on or under the Outer Continental 
Shelf. This revision is necessary to ensure that any petroleum or 
natural gas platforms located on or under the Outer Continental Shelf 
of the United States are required to report under 40 CFR part 98, 
subpart W.
    Changes to Definitions. In this final action, EPA is also amending 
40 CFR 98.6 (definitions). EPA is revising the definition of United 
States as applied under part 98 to clarify that it includes the 
territorial seas. Other facilities located offshore of the United 
States covered by the GHG Reporting Program at 40 CFR part 98 may also 
be affected by this change in the definition of United States. In 
addition to the change to the definition of United States, EPA has 
amended 40 CFR 98.6 by adding a definition of ``Outer Continental 
Shelf.'' This definition is drawn from the definition in the U.S. Code 
and the Clean Air Act, 328(a)(4)(A). These revisions are necessary to 
ensure that facilities on land, in the territorial seas, or on or under 
the Outer Continental Shelf, as defined in 43 U.S.C. 1331, and that 
otherwise meet the applicability criteria of the rule are required to 
report.
    Incorporation by Reference (IBR). In the April 2010 proposal, EPA 
proposed to amend 40 CFR 98.7 by including the following standard 
methods: GRI GlyCalc software, the E&P Tank software, and the American 
Association of Petroleum Geologist (AAPG) Geologic Provinces Code Map. 
EPA has revised the listing of proposed methods for incorporation by 
reference. Hence, in this final action EPA is finalizing amendments to 
40 CFR 98.7 (incorporation by reference) to include standard methods 
referenced in 40 CFR part 98, subpart W. Those include: American 
Association of Petroleum Geologists Geologic Provinces Code Map 
including the Alaska Geological Province Boundary Map; and the Energy 
Information Administration Oil and Gas Field Code Master List.

D. Summary of the Requirements for Petroleum and Natural Gas Systems 
(Subpart W)

1. Summary of the Final Rule
    Source Category Definition. This source category consists of the 
following segments of the petroleum and natural gas systems source 
category:

    <bullet> 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 processes and/or transfers such hydrocarbons to 
storage, transport vessels, or onshore. In addition, offshore 
production includes secondary platform structures connected to the 
platform structure via walkways, storage tanks associated with the 
platform structure, and floating production and storage offloading 
equipment (FPSO). This source category does not include reporting of 
emissions from offshore drilling and, exploration that is not 
conducted on production platforms.
    <bullet> Onshore petroleum and natural gas production. Onshore 
petroleum and natural gas production means all equipment on a well 
pad or associated with a well pad (including compressors, 
generators, or storage facilities), and portable non-self-propelled 
equipment on a well pad or associated with a well pad (including 
well drilling and completion equipment, workover equipment, gravity 
separation equipment, auxiliary non-transportation-related 
equipment, and leased, rented or contracted equipment) used in the 
production, extraction, recovery, lifting, stabilization, separation 
or treating of petroleum and/or natural gas (including condensate). 
This equipment also includes associated storage or measurement 
vessels and all enhanced oil recovery (EOR) operations using 
CO<INF>2</INF>, 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.

[[Page 74462]]

    <bullet> Onshore natural gas processing. Natural gas processing 
means facilities that separate and recovers natural gas liquids 
(NGLs) and/or other non-methane gases and liquids from a stream of 
produced natural gas using 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 CO<INF>2</INF> separated from natural gas streams. This 
segment also includes all residue gas compression equipment owned or 
operated by the natural gas processing facility, whether inside or 
outside the processing facility fence. This source category does not 
include reporting of emissions from gathering lines and boosting 
stations. This source category includes: (1) all processing 
facilities that fractionate and (2) those that do not fractionate 
with throughput of 25 MMscf per day or greater.
    <bullet> Onshore natural gas transmission compression. Onshore 
natural gas transmission compression includes any stationary 
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 
stations may include equipment for liquids separation, natural gas 
dehydration, and tanks for the storage of water and hydrocarbon 
liquids. Residue (sales) gas compression operated by natural gas 
processing facilities are included in the onshore natural gas 
processing segment and are excluded from this segment. This source 
category also does not include reporting of emissions from gathering 
lines and boosting stations--these sources are currently not covered 
by subpart W.
    <bullet> Underground natural gas storage. Underground natural 
gas storage includes subsurface storage, including depleted gas or 
oil reservoirs and salt dome caverns that store 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 compression, dehydration and flow 
measurement, and excluding transmission pipelines); and all the 
wellheads connected to the compression units located at the facility 
that inject natural gas into and remove natural gas from the 
underground reservoirs.
    <bullet> Liquefied natural gas (LNG) storage. LNG storage 
includes onshore LNG storage vessels located above ground, equipment 
for liquefying natural gas, compressors to capture and re-liquefy 
boil-off-gas, re-condensers, and vaporization units for re-
gasification of the liquefied natural gas.
    <bullet> LNG import and export facilities. LNG import equipment 
includes 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.
    <bullet> Natural gas distribution. Natural gas distribution 
includes the distribution pipelines (not interstate transmission 
pipelines or intrastate transmission pipelines) and metering and 
regulating equipment at city gate stations, and excluding customer 
meters, that physically deliver natural gas to end users and is 
operated by a Local Distribution Company (LDC) that is regulated as 
a separate operating company by a public utility commission or that 
is operated as an independent municipally-owned distribution system. 
This segment excludes customer meters and infrastructure and 
pipelines (both interstate and intrastate) delivering natural gas 
directly to major industrial users and ``farm taps'' upstream of the 
local distribution company inlet--these sources are not covered by 
subpart W.

    Facilities from the following segments: (1) Offshore petroleum and 
natural gas production, (2) onshore natural gas processing, (3) onshore 
natural gas transmission compression, (4) underground natural gas 
storage, (5) LNG storage, and (6) LNG import and export equipment, that 
meet the applicability criteria in the General Provisions (40 CFR 
98.2(a)(2)) and summarized in Section II.C of this preamble must report 
GHG emissions. Facilities assessing their applicability in the onshore 
petroleum and natural gas production segment (as defined in 40 CFR 
98.238), must include only emissions from equipment, as specified in 40 
CFR 98.232(c) to determine if they exceed the 25,000 metric ton 
CO<INF>2</INF>e threshold and thus are required to report their GHG 
emissions. Facilities assessing their applicability in the onshore 
natural gas distribution industry segment (as defined in 40 CFR 
98.238), must include only emissions from equipment as specified 40 CFR 
98.232(i) to determine if they exceed the 25,000 metric ton 
CO<INF>2</INF>e threshold and thus are required to report their GHG 
emissions. For other segments, facilities must assess applicability 
based on all source categories for which methods are provided in the 
GHG Reporting Program.
    GHGs to Report. Facilities must report:
    <bullet> Carbon dioxide (CO<INF>2</INF>) and methane 
(CH<INF>4</INF>) emissions from equipment leaks and vents.
    <bullet> CO<INF>2</INF>, CH<INF>4</INF>, and nitrous oxide 
(N<INF>2</INF>O) from combustion.
    <bullet> CO<INF>2,</INF> CH<INF>4,</INF> and nitrous oxide 
(N<INF>2</INF>O) emissions from combustion at flares.
    Reporting Threshold. Facilities that contain petroleum and natural 
gas systems that meet the requirements of 40 CFR 98.2(a)(2) are to 
report GHG emissions under subpart W. For applying the threshold 
defined in 40 CFR 98.2(a)(2), an onshore petroleum and natural gas 
production facility will consider emissions only from equipment 
specified in 40 CFR 98.232(c). For applying the threshold defined in 40 
CFR 98.2(a)(2), a natural gas distribution facility shall consider 
emissions only from equipment specified in 40 CFR 98.232(i).
    GHG Emissions Calculation and Monitoring. The petroleum and natural 
gas source category consists of several segments (e.g., onshore 
petroleum and natural gas production, natural gas processing). Within 
those segments, there are different types of emissions sources, some of 
which appear in multiple segments (e.g., pneumatic devices, blowdown 
vents, etc.). Subpart W provides methodologies for calculating 
emissions from each source type. Although the rule, in some cases, 
allows reporters the flexibility to choose from more than one method 
for calculating emissions from a specific source type, reporters must 
keep record in their monitoring plans as outlined in 40 CFR 98.3(g) of 
this chapter. Table 3 of this preamble summarizes those source types 
and indicates their applicable segments. Reporters of an industry 
segment as defined by 40 CFR 98.230 would report emissions under 
subpart W only from the corresponding source types listed for that 
particular industry segment as defined in 40 CFR 98.232. For example, 
an onshore natural gas transmission compression reporter as defined by 
40 CFR 98.230(a)(4) would report emissions under subpart W only for 
sources defined in 40 CFR 98.232(e). The text following the table 
summarizes the different methodologies reporters must use to monitor 
and calculate their GHG emissions from each emissions source.
    It is important to note, as detailed in Section II.F of this 
preamble, that for specified time periods during the 2011 data 
collection year, reporters may use best available monitoring methods 
for certain emissions sources in lieu of the methods prescribed for 
specific sources below. This is intended to give reporters flexibility 
as they revise procedures and contractual arrangements during early 
implementation of the rule.

[[Page 74463]]



                                                Table 3--Summary of Source Types in Each Industry Segment
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                    LNG
                                                                                 Natural    Natural gas                            Import
                     Source type                        Offshore     Onshore       gas     transmission  Underground     LNG        and     Distribution
                                                       production  production  processing   compression    storage     Storage     export
                                                                                                                                 equipment
--------------------------------------------------------------------------------------------------------------------------------------------------------
Natural gas pneumatic device venting.................                       X                        X            X
Natural gas driven pneumatic pump venting............                       X
Acid gas removal vent stack..........................                       X           X
Dehydrator vent stacks...............................                       X           X
Well venting for liquids unloading...................                       X
Gas well venting during well completions and                                X
 workovers with hydraulic fracturing.................
Gas well venting during well completions and                                X
 workovers without hydraulic fracturing..............
Blowdown vent stacks.................................                       X           X            X                                   X
Onshore production storage tanks.....................                       X
Transmission storage tanks...........................                                                X
Well testing venting and flaring.....................                       X
Associated gas venting and flaring...................                       X
Flare stacks.........................................                       X           X
Centrifugal compressor venting.......................                       X           X            X            X           X          X
Reciprocating compressor rod packing venting.........                       X           X            X            X           X          X
Other emissions from equipment leaks.................                       X           X            X            X           X          X            X
Population Count and Emissions Factor................                       X                                     X           X          X            X
Vented, Equipment Leaks and Flare Emissions                     X
 Identified in BOEMRE GOADS Study....................
Enhanced Oil Recovery hydrocarbon liquids dissolved                         X
 CO2.................................................
Enhanced Oil Recovery injection pump blowdown........                       X
Onshore Petroleum and Natural Gas Production and                            X                                                                         X
 Natural Gas Distribution Combustion Emissions.......
--------------------------------------------------------------------------------------------------------------------------------------------------------

2. Summary of Methodologies for Each Source Type in Table 3 of this 
preamble.
    <bullet> Natural gas pneumatic device venting: Calculate 
CO<INF>2</INF> and CH<INF>4</INF> emissions from natural gas 
pneumatic devices using component count for each type (i.e., 
continuous high bleed, continuous low bleed, and intermittent bleed) 
together with a population emission factor for each type from Tables 
W-1A, W-3, and W-4 of subpart W. Onshore petroleum and natural gas 
production reporters must complete a total count of pneumatic 
devices any time within the first three calendar years. A reporter 
must report pneumatic device emissions annually. For any years where 
activity data (count of pneumatic devices) is incomplete, use best 
available data or engineering estimates to calculate pneumatic 
device emissions.
    <bullet> Natural gas driven pneumatic pump venting: Calculate 
CO<INF>2</INF> and CH<INF>4</INF> emissions using component count of 
natural gas pneumatic pumps together with a population emission 
factor from Table W-1A of subpart W.
    <bullet> Acid gas removal (AGR) vents: Calculate CO<INF>2</INF> 
emissions using one of the following calculation methodologies:

--Use CEMS as specified under subpart C of this section. If CEMS is 
not operated or maintained, a CEMS may be installed.
--Use metered flow and volume weighted CO<INF>2</INF> content of the 
vent stack gas. The approaches available to measure the volume 
weighted CO<INF>2</INF> content include using a continuous gas 
analyzer or sampling the gas quarterly.
--Use metered flow of the inlet natural gas and volume weighted 
CO<INF>2</INF> content of the natural gas flowing into and out of 
the AGR unit. The approaches available to measure the volume 
weighted CO<INF>2</INF> content include using a continuous gas 
analyzer or sampling the gas quarterly.
--Use a process simulator that uses the Peng-Robinson equation of 
state and speciates CO<INF>2</INF> emissions.

    <bullet> Dehydrator vents. Calculate CH<INF>4</INF> and 
CO<INF>2</INF> emissions using the following calculation 
methodologies:

--For glycol dehydrators with a throughput greater than or equal to 
0.4 million standard cubic feet per day, use a software program such 
as GRI GlyCalc or AspenTech HYSYS[reg] for example, to calculate 
emissions. The software program must determine the equilibrium 
coefficient using the Peng-Robinson equation of state, speciates 
CH<INF>4</INF> and CO<INF>2</INF> emissions from dehydrators, and 
have provisions to include regenerator control devices, a separator 
flash tank, stripping gas, and gas injection pump or gas assist 
pump.
--For glycol dehydrators with a throughput less than 0.4 million 
standard cubic feet per day, use daily flow rate of wet natural gas 
together with an emission factor to calculate CO<INF>2</INF> and 
CH<INF>4</INF> emissions. There are separate emission factors for 
dehydrator units with a gas assist pump.
--For desiccant dehydrators, calculate the amount of gas vented from 
the vessel every time it is depressurized for desiccant replacement. 
This involves knowing the dimensions of the dehydrator and percent 
of the vessel that is packed with desiccant, and the time between 
desiccant refilling.

    <bullet> Well venting for liquids unloading: Calculate 
CO<INF>2</INF> and CH<INF>4</INF> emissions using either of the 
following calculation methodologies (the same methodology must be 
used for the entire duration of the calendar year).

--Determine the average gas flow for the duration of the liquids 
unloading using a meter on the vent line. A new average flow rate 
must be calculated every other year starting in the first calendar 
year of reporting. Use the total venting time during the year 
together with the gas flow rate to determine the gas vented during 
liquid unloading.
--Determine the casing dimension, the shut-in pressure, sales flow 
rate and hours that the well was left open to the atmosphere to 
calculate the volume of gas emitted during liquid unloading.

    <bullet> Gas well venting during well completions and workovers 
from hydraulic fracturing: Calculate CO<INF>2</INF> and 
CH<INF>4</INF> emissions using the cumulative vent time during the 
year and the flow rate of gas vented, separately for both 
completions and workovers. Use either of the following methodologies 
to determine the flow rate of the gas.

--Determine the flow rate of vented gas from one well during a well 
completion, and also one well workover event, using a meter 
installed on the vent line. A flow rate determined from a well 
during a well completion can be applied to all wells in

[[Page 74464]]

the same field that undergo a completion. A flow rate determined 
from a well during a well workover can be applied to all wells in 
the same field that undergo a workover. A field-level emissions 
factor must be developed every 2 years starting in the first 
calendar year of reporting.
--Measure the pressure before and after the well choke for both one 
well during a well completion, and also one well workover event. A 
flow rate determined from a well during a well completion can be 
applied to all wells in the same field that undergo a completion. A 
flow rate determined from a well during a well workover can be 
applied to all wells in the same field that undergo a workover. The 
flow rate must be determined in the first year of every 2-year 
period. Separate equations are provided for sonic and sub-sonic 
flow.

    <bullet> Gas well venting during well completions and workovers 
without hydraulic fracturing: Calculate CO<INF>2</INF> and 
CH<INF>4</INF> emissions using the cumulative vent time during the 
year and average daily gas production for each well.
    <bullet> Blowdown vent stacks. Calculate CH<INF>4</INF> and 
CO<INF>2</INF> emissions from blowdown vent stacks by calculating 
the total volume of equipment and vessels blown down between 
isolation valves. This includes the volume of all piping, compressor 
cases or cylinders, manifolds, suction and discharge bottles or any 
other gas-containing volume contained between the isolation valves. 
Total physical volume of less than 50 cubic feet between isolation 
valves of process vessels, piping, and equipment do not have to be 
reported. The total volume contained between isolation valves, which 
can be determined using an engineering equation based on best 
available data, for each process vessel and the number of times it 
was blowndown in the calendar year equals the actual volume of 
emissions, which are then converted to GHG volumes at standard 
conditions and GHG emissions using the concentration of 
CH<INF>4</INF> and CO<INF>2</INF> in the applicable stream. 
Reporters may use the same calculated volumes in subsequent years if 
the hardware has not changed. For process vessels blowndown to a 
flare, calculate the volume of emissions the same as if they were 
not flared, then use that volume as an input parameter in the flare 
stacks section to estimate combustion emissions.

    <bullet> Onshore production storage tanks: Calculate 
CH<INF>4</INF> and CO<INF>2</INF> emissions using one of the 
following calculation methodologies:

--For tanks with separator throughput greater than or equal to 10 
barrels per day, use a software program, such as AspenTECH[reg] or 
API 4697 E&P Tank for example, that uses the Peng-Robinson equation 
of state, models flashing emissions, and speciates CH<INF>4</INF> 
and CO<INF>2</INF> emissions from tanks. The low pressure separator 
oil composition and Reid vapor pressure can be determined using the 
default values within the software program, or using a 
representative sample analysis.
--Alternatively, for tanks with separator throughput greater than or 
equal to 10 barrels per day, you may assume all of the 
CH<INF>4</INF> and CO<INF>2</INF> in the low pressure separator oil 
is emitted. The low pressure separator oil composition shall be 
determined using an appropriate sample analysis, or default oil 
compositions in software programs.
--For wells with oil production greater than or equal to 10 barrels 
per day that flow directly to a tank without going through a 
separator, calculate emissions by using an appropriate sample 
analysis and assuming all of the CH<INF>4</INF> and CO<INF>2</INF> 
are emitted.
--For separator throughput or wells flowing directly to tanks with 
throughput less than 10 barrels per day, use a population emission 
factor together with the flow rate.
--Account for occurrences when the separator dump valve is 
improperly open and bypassing gas to the tank through the liquid, by 
determining the number of hours the dump valve is open and scaling 
the emissions upwards using the correction factor. The number of 
hours the dump valve is open can be determined using the maintenance 
or operations records as follows: (1) Assume that if a dump valve is 
found open, that it was open from either the beginning of the 
calendar year, or since the most recent maintenance or operations 
record confirming proper closure of the dump valve and (2) Assume 
that a dump valve is improperly open until there is a maintenance or 
operations record showing that the dump valve is closed or to the 
end of the calendar year.

    <bullet> Transmission storage tanks. For transmission storage 
tanks, once per calendar year reporters must monitor the tank vapor 
vent stack using an optical gas imaging instrument, to view the 
emissions for 5 minutes. Alternatively, the scrubber dump valves can 
be monitored with an acoustic leak detector. If the vent stack emits 
continuously over that time period, then the reporter must use 
either a meter or an acoustic leak detection device to measure the 
flow rate of the vent to determine emissions. This will quantify 
tank emissions resulting from malfunctioning scrubber dump valves. 
If a tank is vented to a flare, then use the onshore petroleum and 
natural gas production storage tanks methodology option 1 
(simulation) to estimate the volume and composition of vapors 
flared. Then use the flare stacks methodology to estimate the 
emissions.
    <bullet> Well testing venting and flaring. Calculate 
CH<INF>4,</INF> CO<INF>2,</INF> and N<INF>2</INF>O emissions from 
well testing venting and flaring by multiplying available data from 
production records on the gas-to-oil ratio for produced hydrocarbon 
liquids, by the flow rate (in barrels of oil per day) of the well 
being tested, by the number of days in the calendar year the well is 
tested. If gas-to-oil ratios are not available, use a sample 
analysis to determine gas-to-oil ratios. For the calculated testing 
gas volume that is flared, use the method set forth for flare stacks 
to estimate the emissions.
    <bullet> Associated gas venting and flaring. Calculate 
CH<INF>4,</INF> CO<INF>2,</INF> and N<INF>2</INF>O emissions from 
associated gas venting and flaring by multiplying available data 
from production records on the gas-to-oil ratio for produced 
hydrocarbon liquids, by the volume of liquids produced in the 
calendar year. The gas-to-oil ratios can be determined by the use of 
a representative gas-to-oil ratio of wells in the same field. If 
gas-to-oil ratios are not readily available, use a sample analysis 
to determine gas-oil ratios. For the calculated associated gas 
volume that is flared, use the method set forth for flare stacks to 
estimate the emissions.
    <bullet> Flare stacks. Calculate CH<INF>4,</INF> CO<INF>2,</INF> 
and N<INF>2</INF>O emissions from flare stacks by metering or using 
engineering estimation to determine the volume of gas sent to the 
flare, and the gas composition to then estimate the portion that is 
combusted and the portion that is not combusted, using the flare 
efficiency. Where methodologies for other sources in subpart W refer 
to this methodology in order to estimate flaring emissions, use the 
estimated volume of flared gas from those sources as the gas to 
flare volume in this methodology, and report those emissions under 
those sources. Calculate N<INF>2</INF>O from flare stacks using the 
methodology set forth for in 40 CFR 98.233(z).
    <bullet> Centrifugal compressor venting.
--Calculate CH<INF>4</INF> and CO<INF>2</INF> emissions from wet 
seal oil degassing vents in onshore petroleum and natural gas 
production by counting the total population of centrifugal 
compressors and multiplying it by the appropriate emission factors.

--Calculate CH<INF>4</INF> and CO<INF>2</INF> emissions from wet 
seal and dry seal centrifugal compressor blowdown vents, wet seal 
degassing, and unit isolation valves for wet seal and dry seal 
compressors (see Table 4 of this preamble) found in onshore natural 
gas processing, onshore natural gas transmission compression, 
underground natural gas storage, LNG storage, and LNG import and 
export equipment by:
--Measuring venting from blowdown vents when the compressor is found 
in the operating mode using a meter.
    - Measuring wet seal degassing venting when the compressor is 
found in the operating mode using a meter.
--Measuring venting from unit isolation valves when the compressor 
is found in not operating, depressurized mode using a meter. If 
these sources are vented through a common manifold, you must measure 
each vent source separately. Determine average emissions from each 
mode of operation by summing the emissions from each source in each 
mode and dividing it by the total population measured. The result 
will be an emission factor per compressor per hour for each mode of 
operation. Multiply each emission factor by the total number of 
compressor-hours in each mode of operation. Reporters are not 
required to shutdown compressors to conduct measurements. The owner 
or operator must schedule an annual measurement of each compressor 
and the owner or operator can take the measurement in the mode in 
which the compressor is found during the annual measurement. 
However, the owner or operator must conduct a measurement of each 
compressor in the not operating, depressurized mode at least once 
every three calendar years. Please see Compressor Modes and 
Threshold, Docket EPA-HQ-OAR-2009-0923.

[[Page 74465]]



     Table 4--Summary of Emission Factor Categories for Centrifugal
                           Compressor Venting
------------------------------------------------------------------------
                                             Operating mode
                              ------------------------------------------
          Component                                  Not operating--
                                  Operating           depressurized
------------------------------------------------------------------------
Blowdown Vent................  Individual       Not Applicable.
                                Factor.
Wet Seal Oil Degassing Vent..  Individual       Not Applicable.
                                Factor.
Unit Isolation Valve.........  Not Applicable.  Individual Factor.
------------------------------------------------------------------------

    <bullet> Reciprocating compressor rod packing venting. Calculate 
CH<INF>4</INF> and CO<INF>2</INF> emissions from reciprocating 
compressor rod packing venting in onshore petroleum and natural gas 
production by counting the total population of reciprocating 
compressors and multiplying it by the emission factors provided in 
40 CFR 98.233(p)(10). Calculate CH<INF>4</INF> and CO<INF>2</INF> 
emissions for reciprocating compressor blowdown valves, rod packing, 
and unit isolation valves (see Table 5 of this preamble) from 
onshore natural gas processing, onshore natural gas transmission 
compression, underground natural gas storage, LNG storage, and LNG 
import and export equipment by:

--Measuring venting from blowdown vents when the compressor is found 
in operating and standby pressurized modes using a meter.
--Measuring rod packing vents when the compressor is found in 
operating and standby pressurized modes using a meter. If there is 
not a vent line, a rigorous approach of scanning for all potential 
leakage paths for the gas must be used and quantified with a meter, 
high volume sampler, or calibrated bag as appropriate.
--Measuring venting from unit isolation valves using a meter when 
the compressor is found in not operating, depressurized mode. For 
through-valve leakage to open ended vents, such as unit isolation 
valves on not operating depressurized compressors, acoustic leak 
detection devices may also be used.

    If these sources are vented through a common manifold, you must 
measure each vent source separately. Determine average emissions 
from each mode of operation by summing the emissions from each 
source in each mode and dividing it by the total population 
measured. The result will be an emission factor per compressor per 
hour for each mode of operation. Multiply each emission factor by 
the total number of compressor-hours in each mode of operation. 
Reporters are not required to shut down compressors to conduct 
measurements. The owner or operator must conduct a measurement of 
each compressor, and measure the compressor in the mode as it is 
found during the annual measurement. However, the owner or operator 
must conduct at least one measurement of each compressor in the not 
operating, depressurized mode at least one time every 3 calendar 
years. Please see ``Compressor Modes and Threshold'' Docket EPA-HQ-
OAR-2009-0923.

               Table 5--Summary of Emission Factor Categories for Reciprocating Compressor Venting
----------------------------------------------------------------------------------------------------------------
                                                                   Operating mode
             Component             -----------------------------------------------------------------------------
                                          Operating         Standby pressurized    Not operating--depressurized
----------------------------------------------------------------------------------------------------------------
Blowdown Vent.....................   Use measurements in either mode to develop   Not Applicable.
                                                   combined factor.
----------------------------------------------------------------------------------------------------------------
Rod Packing Seals.................  Individual Factor....  Individual Factor....  Not Applicable.
----------------------------------------------------------------------------------------------------------------
Unit Isolation Valve..............  Not Applicable.......  Not Applicable.......  Individual Factor.
----------------------------------------------------------------------------------------------------------------

    <bullet> Leak detection and leaker factors (onshore natural gas 
processing, onshore natural gas transmission compression, 
underground natural gas storage, LNG storage, LNG import export, 
natural gas distribution). Perform a leak detection survey using one 
of the three following methods:

--Use an optical gas imaging instrument. The method must be used for 
all sources that cannot be monitored without elevating personnel 
more than 2 meters above a support surface.
--Use an infrared laser beam illuminated instrument.
--Use Method 21.
--Multiply the count of each type of leaking component by the 
appropriate leaker factors in Tables W-2, W-3, W-4, W-5, W-6, and W-
7 of subpart W. Tubing systems less than 0.5 inch are exempt from 
reporting.
--For natural gas distribution, leak detection is required only for 
above ground metering and regulating stations (also called ``gate 
stations'') at which custody transfer occurs. The leak detection and 
monitoring requirements prescribed in subpart W do not include 
customer meters. All facilities under this source must conduct at 
least one leak survey each calendar year. Multiple leak surveys may 
be conducted in order to account for leak repairs. If multiple 
surveys are chosen by the owner or operator and performed, each 
survey must be facility wide.
--If only one leak survey is conducted in the calendar year, assume 
that all leaks found emit for the entire year.
--If multiple leak surveys are conducted, assume that each leak that 
is found has been emitting since the last survey; or since the 
beginning of the calendar year. Assume that each leak found during 
the last leak survey in a calendar year continues to emit until the 
end of the calendar year.
    <bullet> Population count and emission factor. Calculate 
CH<INF>4</INF> and CO<INF>2</INF> emissions from the sources listed 
in 40 CFR 98.233(r).

--For onshore petroleum and natural gas production, each component 
must either be counted individually; or major equipment pieces must 
be counted and then the appropriate average component counts should 
be applied using Tables W-1B, W-1C, and W-1D of subpart W. The most 
recent gas composition that is representative of the field must be 
used to determine the percent of the leaked gas that is 
CH<INF>4</INF> and CO<INF>2</INF>.
--For underground natural gas storage, the emission factors in Table 
W-4 of subpart W must be applied to population counts of components 
on storage wellheads.
--For LNG storage, the emission factor for vapor recovery 
compressors, must be applied to the total population count.
--For LNG import and export equipment, the emission factor for vapor 
recovery compressors must be applied to the total population count.
--For natural gas distribution, all emissions from above ground 
custody transfer metering and regulating stations as determined by 
leak detection surveys must be totaled and then divided by the total 
number of surveyed meter runs to develop an average emission factor 
for above grade metering and regulating stations. This average 
emission factor will be multiplied by the total number of above 
ground metering and regulating stations meter runs at which custody 
transfer does not occur to estimate emissions from those stations. 
Emission factors in Table W-7 of subpart W will be used to account 
for equipment leaks in underground meter and regulation stations, 
pipelines, and service lines.

    <bullet> Offshore production. Calculate CO<INF>2</INF> and 
CH<INF>4</INF> emissions from offshore petroleum and

[[Page 74466]]

natural gas production facilities using the methods outlined by 
BOEMRE \3\ Gulfwide Emissions Inventory Study, herein after referred 
to as ``GOADS.'' Offshore production facilities are not required to 
report portable emissions to EPA.
---------------------------------------------------------------------------

    \3\ The Bureau of Ocean Energy Management, Regulation, and 
Enforcement (BOEMRE) was formerly known as Minerals Management 
Service (MMS).

--Offshore production facilities reporting under the BOEMRE GOADS 
program must report where available the same annual emissions as 
calculated by BOEMRE using activity data submitted by platform 
operators in the latest GOADS study calculated by BOEMRE's data base 
management system. For the 2011 calendar year, offshore production 
facilities currently under the GOADS program must report the latest 
published emissions from the GOADS study for platforms in service in 
the GOADS study year. In subsequent calendar years when BOEMRE 
publishes an updated GOADS study, reporters shall report emissions 
based on that latest GOADS study. For each calendar year that does 
not overlap with the GOADS publication of a new study, reports for 
platforms operating in the current year that were also operating in 
the last published GOADS study should be adjusted based on the 
operating time for each platform relative to the operating time in 
the previous reporting period.
--For offshore production facilities that do not report under the 
BOEMRE GOADS program (non-GOADS reporters), monthly activity data 
from applicable offshore production facilities must be collected for 
the first calendar year in accordance with the latest GOADS program 
instructions. Calculation of GHG emissions must be performed using 
the latest GOADS program emission factors and methodologies as 
outlined in the latest published GOADS study. In subsequent calendar 
years, facilities not under GOADS jurisdiction must follow the data 
collection cycle as required in the GOADS program by collecting new 
monthly activity data, estimating GHG emissions using the latest 
GOADS program emission factors and methodologies and report those 
emissions to EPA. For each calendar year that does not overlap with 
a new GOADS study publication, offshore production facilities not 
reporting under the BOEMRE GOADS program must report the last 
reported emissions data with emissions adjusted based on the 
operating time for each platform relative to operating time in the 
previous reporting period. Thus, these facilities will gather data 
and estimate updated emissions on the same cycle as facilities 
reporting to the GOADS program.
--For either first or subsequent year reporting, platforms either 
within or outside of GOADS jurisdiction that were not covered in the 
previous GOADS data collection cycle shall collect monthly activity 
data from platform sources in accordance with the latest GOADS 
program instructions and calculate GHG emissions using the latest 
GOADS program emission factors and methodologies.
--If BOEMRE discontinues or delays their GOADS survey by more than 4 
years, then offshore production facilities shall collect monthly 
activity data every 4 years from platform sources in accordance with 
the latest published version of the GOADS program instructions, and 
annual GHG emissions shall be calculated using latest GOADS program 
emission factors and methodologies.
--Offshore production facilities subject to subpart W must report 
stationary combustion emissions under subpart C of part 98.
--All Offshore production facilities, whether out of or under the 
jurisdiction of BOEMRE GOADS program are to adhere to the monitoring 
and QA/QC requirements in the applicable BOEMRE regulations.

    <bullet> EOR Hydrocarbon liquids dissolved CO<INF>2</INF>. 
Calculate CO<INF>2</INF> emissions downstream of storage tanks from 
hydrocarbon liquids produced as a result of enhanced oil recovery 
operations by conducting annual composition sampling of the produced 
hydrocarbon liquids by taking samples downstream of the storage 
tank. Use the mass of CO<INF>2</INF> from the sample to determine 
the mass of CO<INF>2</INF> dissolved in hydrocarbons beyond storage 
per barrel of produced liquid hydrocarbons.
    <bullet> EOR injection pump blowdown. Calculate CO<INF>2</INF> 
emissions from enhanced oil recovery critical phase CO<INF>2</INF> 
injection pump blowdowns by calculating the volume of gas-containing 
structures between isolation valves, including piping. Use 
engineering estimates and best available data to determine the 
volume of gas-containing structures between isolation valves. The 
volumes calculated may be used in subsequent years if the hardware 
has not changed. Maintain logs of the number of blowdowns in the 
calendar year for each EOR pump. Using an appropriate standard 
method published by a consensus-based standards organization or, if 
no such standard exists, an industry standard practice, determine 
the density of the supercritical EOR injection gas. Calculate 
emissions using the number of blowdowns, the volume of the blown 
down equipment, the mass fraction of CO<INF>2</INF> in the injection 
gas, the density of the injection gas, and a conversion factor.
    <bullet> Onshore petroleum and natural gas production and 
natural gas distribution combustion emissions. Calculate 
CO<INF>2</INF>, CH<INF>4</INF> and N<INF>2</INF>O combustion 
emissions from stationary and portable combustion equipment in 
onshore petroleum and natural gas production and stationary 
combustion equipment in natural gas distribution using the following 
methods:

--If the fuel combusted is listed in Table C-1 of subpart C, or any 
blend of the fuels listed, use the Tier 1 methodology of subpart C.
--Following the methodologies in 40 CFR 98.233(z), if the fuel 
combusted is field gas or a combination of field gas or process vent 
gas and one or more fuels listed in Table C-1 of subpart C, then use 
the volume of fuel and the composition of the fuel to calculate 
CO<INF>2</INF> emissions. If meters are installed on the fuel 
stream, the meter must be used to determine the volume of fuel 
combusted; otherwise the reporter can estimate that volume by 
installing a permanent flow meter or use engineering calculations. 
If a continuous gas analyzer is installed on the fuel stream, the 
composition reading must be used; otherwise another accepted method 
to estimate the composition may be used.
--Emissions from external fuel combustion sources with a rated heat 
capacity less than or equal to 5 mmBtu/hour do not have to be 
reported. Only activity data (unit count by type of unit) for such 
sources is to be reported.
--Calculate N<INF>2</INF>O emissions from combustion equipment using 
emission factors and the fuel volume consumed. The high heat value 
of the fuel can be estimated using Table C-1 of subpart C if 
possible. If the fuel is field gas or process vent gas, a default 
high heat value is provided. If another fuel, not covered by Table 
C-1 of subpart C or field gas or process vent gas, is used; then the 
appropriate methodology from subpart C to estimate high heat value 
must be used.

    Data Reporting Requirements. In addition to the information 
required to be reported by the General Provisions (40 CFR 98.3(c)), 
reporters must submit additional data that are needed for EPA 
verification of the reported GHG emissions from petroleum and natural 
gas systems. The specific data to be reported are found in 40 CFR part 
98, subpart W.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)), reporters must keep records of additional 
data used to calculate GHG emissions. These records are described in 40 
CFR part 98, subpart W.
    Definitions. EPA added definitions that are specific to subpart W 
to 40 CFR 98.238 to avoid any confusion with the definitions found in 
40 CFR 98.6. For compliance with subpart W, the subpart W specific 
definitions apply instead of any of the same definitions also found in 
subpart A.
    We are including a definition of the term ``Offshore'' in 40 CFR 
98.238 to fully identify those petroleum and natural gas production 
platforms, secondary platforms and associated storage tanks covered by 
this rule.
    We are also including two distinctive definitions of facility for 
onshore petroleum and natural gas production and for natural gas 
distribution. Defining a facility in these cases is not as 
straightforward as other industry segments covered under subpart W. For 
some segments of the industry (e.g., onshore natural gas processing, 
onshore natural gas transmission compression, and offshore petroleum 
and natural gas production), identifying the facility is clear since 
there are physical boundaries and ownership structures

[[Page 74467]]

that lend themselves to identifying the scope of reporting and 
responsible reporting entities. However, in onshore petroleum and 
natural gas production and natural gas distribution such distinctions 
are more challenging. As explained in the April 2010 proposal, EPA 
evaluated existing definitions used under current regulations and 
determined that it was necessary to provide a unique definition of 
facility for each of these two segments in order to ensure that the 
reporting delineation is clear, avoid double counting, and ensure 
appropriate emissions coverage. For more information please see the 
preamble for the April 2010 proposal (75 FR 18608) and the Greenhouse 
Gas Emissions from Petroleum and Natural Gas Industry: Background 
Technical Support Document (EPA-HQ-OAR-2009-0923).
    These definitions are intended only for purposes of subpart W and 
are not intended to affect to definition of a facility as it might be 
applied in any other context of the Clean Air Act.
    First, as proposed in April 2010, the definition of natural gas 
distribution facility for this subpart is 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. This facility 
definition provides clear reporting delineation because the equipment 
that they operate is clearly known, the ownership is clear to one 
company, and reporting at this level is consistent with 40 CFR part 98. 
In this action, EPA is finalizing this definition for the natural gas 
distribution industry segment. This facility definition for natural gas 
distribution will result in 90 percent GHG emissions coverage of this 
industry segment.
    Second, as proposed in April 2010, the definition of an onshore 
petroleum and natural gas production facility for this subpart is all 
petroleum or natural gas equipment associated with all petroleum or 
natural gas production wells and CO<INF>2</INF> EOR operations that are 
under common ownership or common control including leased, rented, and 
contracted activities by an onshore petroleum and natural gas 
production owner or operator and that are located in a single 
hydrocarbon basin as defined in 40 CFR 98.238. Where a person or entity 
owns or operates more than one well in a basin, then all onshore 
petroleum and natural gas production equipment associated with all 
wells that the person or entity owns or operates in the basin would be 
considered one facility. In the April 2010 proposal, EPA evaluated at 
least two available industry recognized definitions that identify 
hydrocarbon basins: One from the United States Geological Survey (USGS) 
and the other from the American Association of Petroleum Geologists. 
Basins are mapped to county boundaries only to give a surface 
manifestation to the underground geologic boundaries. EPA decided to 
use the AAPG geologic definition of basin because it 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. Hence, in this 
action, EPA is finalizing the facility definition at the basin level 
for the onshore petroleum and natural gas production industry segment 
because the operational boundaries and basin demarcations are clearly 
defined and are widely known, and reporting at this level would provide 
the necessary coverage of GHG emissions to inform policy. In addition, 
EPA has clarified its intent by stating that onshore petroleum and 
natural gas production equipment associated with all petroleum or 
natural gas production wells and CO<INF>2</INF> EOR operations continue 
to include any leased, rented or contracted activities by the owner or 
operator of those wells in that basin. This facility definition for 
onshore petroleum and natural gas production will result in 85 percent 
GHG emissions coverage of this industry segment.
    Finally, in this final action, EPA has replaced the term ``fugitive 
emissions'' with ``equipment leaks.'' This change was made to ensure 
consistency with the terminology in the Alternative Work Practice to 
Detect Leaks from Equipment for 40 CFR parts 60, 63, and 65.

E. Summary of Major Changes and Clarifications Since Proposal

    The major changes and clarifications in subpart W since the April 
2010 proposal are identified in the following list. For a full 
description of the rationale for these and any other significant 
changes to 40 CFR part 98, subpart W, see the Mandatory Greenhouse Gas 
Reporting Rule: EPA's Response to Public Comments, Subpart W: Petroleum 
and Natural Gas Systems. The changes are organized following the 
different sections of the subpart W regulatory text.
1. Definition of the Source Category
    <bullet> EPA revised the definition for onshore natural gas 
processing and onshore petroleum and natural gas production to exclude 
gathering lines and boosting stations from the source category.
    <bullet> EPA revised the definition of onshore petroleum and 
natural gas production to include equipment on a well pad or associated 
with a well pad, due to the growing industry practice of multi-well 
pads, where equipment may serve one well on a pad or several wells on a 
pad.
    <bullet> EPA has revised the definition of natural gas processing 
to clarify that this industry segment includes (1) all processing 
facilities that fractionate and (2) those that do not fractionate with 
throughput of 25 MMscf per day or greater.
    <bullet> EPA has revised the definition for the natural gas 
processing industry segment by removing the term ``plant'' from the 
segment name to ensure consistency with terminology used by other 
industry segment definitions.
    <bullet> EPA clarified that meters and regulators in the natural 
gas distribution industry segment do not include customer meters.
2. Reporting Threshold
    <bullet> EPA is amending the reporting threshold language in 
subpart W to clarify that onshore petroleum and natural gas production 
facilities and onshore natural gas distribution facilities must report 
emissions only from sources specified in subpart W. This amendment was 
necessary to clearly define what emissions sources are to be included 
for considering the threshold in determining applicability for these 
two industry segments because they each have a different definition of 
the term ``facility'' than what is defined in the general provisions of 
part 98.
3. GHGs To Report
    <bullet> EPA removed the reporting requirements for produced water 
from coal bed methane (CBM) and enhanced oil recovery (EOR) operations.
4. Monitoring, QA/QC, and Calculating Emissions
    <bullet> For industry segments where equipment leak detection is 
required (onshore natural gas processing, onshore natural gas 
transmission compression, underground natural gas storage, LNG storage 
and LNG import and export equipment, and natural gas distribution 
facilities) EPA is including the option to use Method 21 and infrared 
laser beam illuminated instruments to detect leaks for sources that are 
accessible. Inaccessible equipment leaks and vented emissions are still 
required to be monitored using an optical gas imaging instrument.

[[Page 74468]]

    <bullet> For applicable industry segments (onshore natural gas 
processing, onshore natural gas transmission compression, underground 
natural gas storage, LNG storage and LNG import and export equipment), 
EPA clarified the monitoring and reporting requirements for centrifugal 
and reciprocating compressors. Reporters are required to conduct an 
annual measurement of each compressor in the mode in which it is found 
at the time of the annual measurement. However, EPA requires reporters 
to conduct at least one measurement of each compressor in the not 
operating, depressurized mode during every 3-year period. Commenters 
suggested to EPA that based on their operational experience, 3 years is 
an appropriate maximum time period during which compressors will be 
shutdown at least once for routine maintenance, such that operators 
would not need to shutdown compressors specifically for the purposes of 
monitoring. For more detail, please see EPA-HQ-OAR-2009-0923-1011 
excerpt 44. Also see ``Compressor Modes and Threshold'' Docket EPA-HQ-
OAR-2009-0923.
    <bullet> EPA clarified reporting requirements and in some cases 
included alternative data collection methodologies for certain sources 
to balance burden with data quality and emissions coverage:
    --For onshore petroleum and natural gas production, EPA is allowing 
the use of major equipment counts and default average counts for 
associated components rather than requiring individual counts for all 
components to determine populations to which to apply component 
emission factors.
    --As compressors in onshore petroleum and natural gas production 
are small in size, EPA is allowing the use of emission factors for 
calculating GHG emissions from centrifugal and reciprocating 
compressors in onshore petroleum and natural gas production rather than 
conducting an annual measurement of each compressor in the mode in 
which it is found.
    --EPA is allowing onshore petroleum and natural gas production 
reporters to complete a total count of pneumatic devices any time 
within the first three calendar years. A reporter must report pneumatic 
device emissions annually. For any years where activity data (count of 
pneumatic devices) is incomplete, use best available data or 
engineering estimates to calculate pneumatic device emissions.
    --For collecting gas composition data for produced natural gas, EPA 
is allowing reporters to use existing sampling data (e.g., composition 
analysis of gas sold) if reporters do not have a continuous gas 
composition analyzer already installed.
    --EPA is including emission factors for calculating GHG emissions 
from the following sources: vented GHG emissions from onshore petroleum 
and natural gas production tanks receiving oil from separators or 
directly from wells with less than 10 barrels per day throughput; 
onshore petroleum and natural gas production and onshore natural gas 
processing dehydrators with less than 0.4 million standard cubic feet 
per day throughput; vented GHG emissions from all onshore petroleum and 
natural gas production pneumatic devices and pneumatic pumps, and 
pneumatic devices in onshore natural gas transmission compression 
facilities and underground natural gas storage facilities.
    --For both the onshore petroleum and natural gas production 
industry segment and the natural gas distribution industry segment, 
external fuel combustion emissions from portable or stationary 
equipment with rated heat capacity less than or equal to 5 mmBtu/hr, 
only activity data must be reported.
    --Blowdown emissions from equipment vessel chambers totaling less 
than 50 cubic feet are not required to be reported.
    --For reciprocating and centrifugal compressor measurement 
requirements, EPA clarified that the installation of permanent meters 
is an option but is not required; temporary meters are acceptable. In 
addition, through-valve leakage to open ended vents, such as unit 
isolation valves on not operating depressurized compressors and 
blowdown valves on pressurized compressors, may be measured using 
acoustic leak detection devices.
    <bullet> EPA is allowing Best Available Monitoring Methods for 
certain sources and time periods (for more detailed information, refer 
to Section II.F of this preamble).
    <bullet> For transmission storage tanks, EPA is allowing reporters 
to use an acoustic leak detection device to monitor leakage through 
compressor scrubber dump valves into the tank.
5. Applicability
    To assist reporters in determining applicability, EPA is planning 
to develop screening tools to assist in the determination of which 
entities may potentially be required to report under subpart W of 40 
CFR part 98.

F. Summary of Comments and Responses

    This section contains a brief summary of major comments and 
responses. EPA received many comments on this subpart covering numerous 
topics. EPA's responses to all comments, including those below, can be 
found in the comment response document for petroleum and natural gas 
systems in Mandatory Greenhouse Gas Reporting Rule: EPA's Response to 
Public Comments, Subpart W: Petroleum and Natural Gas Systems. 
Additional comments and responses related to cost issues on the 
proposed rule can be located in Section III.B.2 of this preamble.
1. Definition of the Source Category
    Comment: Numerous commenters objected to the inclusion of gathering 
lines and booster stations in the natural gas processing industry 
segment definition. Commenters specifically stated that including 
gathering lines and booster stations would result in undue burden on 
reporters stemming from (1) The additional cost to include gathering 
lines and boosting stations that typically are associated with a single 
natural gas processing facility, and (2) the numerous complexities and 
variations of ownership that currently exist with gathering lines and 
boosting stations. One commenter further detailed that there are at 
least three different owner/operator variations that exist ranging from 
a scenario where a single company owns and/or operates the wells, 
gathering lines, and natural gas processing facility, to a scenario 
where a single company owns the wells, a second distinct company (or 
multiple companies) own the gathering lines, and a third distinct 
company may own the natural gas processing facility. The commenter 
further explained that these scenarios are further complicated because 
the variations in gas flow fluctuate daily due to the need to balance 
production demands for natural gas against the capacity of the 
gathering lines and the natural gas processing facility.
    Finally, a number of commenters requested that the gathering lines 
and boosting stations be excluded from the natural gas processing 
industry segment definition or be defined as a separate industry 
segment.
    Response: EPA has decided not to include gathering lines and 
boosting stations as an emissions source in subpart W at this time. The 
primary reason for excluding gathering lines and boosting stations at 
this time is that emissions coverage from gathering lines and boosting 
stations within the natural gas processing industry segment requires 
further analysis to ensure an effective coverage of emissions from this 
source in order to appropriately inform

[[Page 74469]]

future policy decisions. As a result, EPA is continuing to review the 
comments received and similar comments raised to ensure an effective 
coverage of emissions from this source, and is considering the most 
appropriate mechanism for future actions to address the collection of 
appropriate data on gathering lines and boosting stations while 
minimizing industry burden.
    Comment: Several commenters stated that meters and regulators (M&R) 
were not clearly defined and could result in the inclusion of customer 
meters in the reporting requirements for the natural gas distribution 
industry segment.
    Response: EPA did not intend to require reporting of GHG emissions 
from customer meters in subpart W. In this final action, EPA has 
clarified its intent to not require reporting of GHG emissions from 
customer meters. The definition of the natural gas distribution 
industry segment and the listing of GHGs to report under this industry 
segment have been refined to make clear what emissions are to be 
reported for this industry segment.
    Comment: Commenters noted that many facilities would fall under 
more than one industry segment in a calendar year and requested 
clarification as to which industry segment such a facility would be 
required to report under. In addition some commenters noted that they 
have equipment from multiple industry segments located in the same 
physical space.
    Response: EPA has reviewed these comments and has addressed them. 
Please see response to comment EPA-HQ-OAR-2009-0923-1024-14 in the 
Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public 
Comments.
2. GHGs To Report
    Comment: Numerous commenters argued against the reporting of 
emissions, specifically combustion emissions, from portable equipment 
for the onshore petroleum and natural gas industry segment. Commenters 
noted that tracking emissions from portable non-self propelled 
equipment would result in heavy burden due to the fact that the 
majority of portable equipment are operated by an entity that is 
separate from the owner. Further, commenters stated that the reporting 
of emissions from portable equipment will only marginally increase 
coverage of the proposed rule. Some commenters argued that subpart C 
excludes portable equipment from combustion emissions reporting, and 
questioned why it was required for subpart W.
    Response: EPA disagrees with commenters and has finalized the 
reporting requirements for GHG emissions from portable non-self 
propelled equipment in subpart W, including emissions from drilling 
rigs, dehydrators, compressors, electrical generators, steam boilers, 
and heaters with external combustion rated heat capacity above 5 mmBtu/
hour.
    In order to manage the burden, the emissions estimation methods for 
portable equipment require the use of existing data, for the most part. 
Moreover, the allowance of Best Available Monitoring Methods (described 
later in this preamble) would provide reporters additional time to 
modify contractual arrangements with service providers. The decision to 
retain the reporting requirements for portable equipment GHG emissions 
was based on EPA's analysis of the contribution to GHG emissions, both 
combustion and process, from portable equipment in onshore production. 
It is estimated that portable non self-propelled equipment is 
responsible for over 45 percent of total emissions from onshore 
petroleum and natural gas production. Please see ``Portable Combustion 
Emissions'' Docket EPA-HQ-OAR-2009-0923 for the complete analysis. 
While EPA is not excluding portable equipment, for certain emissions 
sources, EPA agrees with comments that alternative methodologies are 
appropriate and viable for collecting these data. EPA has conducted an 
extensive review of the emissions contribution relative to reporting 
burden and modified the final rule to simplify the requirements for 
external combustion equipment that fall below a rated heat capacity of 
5 mmBtu/hr for the onshore petroleum and natural gas industry segment 
and the natural gas distribution industry segment. Please see 
``Portable Combustion Emissions'' Docket EPA-HQ-OAR-2009-0923 and 
``Equipment Threshold for Small Combustion Units'' Docket EPA-HQ-OAR-
2009-0923 for the analysis. Equipment that fall below the specified 
mmBtu level for the applicable industry segments would not have to 
conduct monitoring for combustion emissions, and would only be required 
to report activity data which would be total number of external fuel 
combustion units with a rated heat capacity of equal to or less than 5 
mmBtu/hr by type of unit.
3. Monitoring, QA/QC, and Calculating Emissions
    Comment: EPA received numerous comments on the use of the optical 
gas imaging instrument for detecting GHG emissions from equipment 
leaks. Several commenters expressed support for the use of optical gas 
imaging instruments prescribed in the rule, stating that using this 
equipment would result in cost savings to industry as it would reduce 
burden and time by quick survey of all emissions sources at one time. 
In addition, several commenters specifically requested that EPA also 
allow the use of organic vapor analyzers (OVA), toxic vapor analyzers 
(TVA) and infrared laser beam illuminated instruments as alternative 
technologies to the optical gas imaging instruments proposed for 
emissions detection.
    Response: EPA has evaluated alternative methods for detection of 
equipment leaks for their viability and comparative accuracy to the 
optical gas imaging instrument in the proposed rule. EPA agrees with 
commenters and has modified the final rule to include the options to 
use OVA/TVA devices or infrared laser beam illuminated instruments for 
leak detection for all emissions sources across all industry segments 
with the exception of inaccessible sources. EPA is still requiring that 
reporters use optical gas imaging instruments for inaccessible sources 
due to potential safety and cost concerns related to leak detection of 
sources that cannot be physically accessed from a fixed, supportive 
surface with a hand held leak detection device such as OVA/TVA, or 
which do not have a reflective background for an IR laser detection 
device. While EPA has determined that the methodologies in this rule 
are viable and appropriate for collecting this type of GHG data, EPA 
will continue to evaluate other potential methods for detecting methane 
emissions in the petroleum and natural gas sector.\4\
---------------------------------------------------------------------------

    \4\ While this activity is in a nascent stage, EPA is conducting 
ongoing research on experimental mobile monitoring methods to locate 
and quantify equipment leak emissions from petroleum and natural gas 
fields. In addition to increasing our knowledge about emissions from 
equipment leaks from petroleum and natural gas fields, if this 
proves to be a robust approach, it could be one viable alternative 
for measuring emissions and EPA would consider a rulemaking to add 
it as an acceptable method to this subpart.
---------------------------------------------------------------------------

    Comment: Numerous commenters disagreed with EPA's assessment of the 
feasibility of conducting one measurement for each reciprocating or 
centrifugal compressor in each of the operational modes (operating, 
standby pressurized, not operating/depressurized) that would occur 
during a calendar year. Commenters specifically stated that common 
industry practice is to have a compressor in operating mode for several 
years before it is taken offline for routine maintenance and servicing, 
thereby taking a compressor offline for the sole purpose of measurement 
as

[[Page 74470]]

prescribed in the rule would result in undue burden to the industry and 
result in additional GHG emissions.
    Response: EPA did not intend for compressors to be taken offline in 
order for reporters to collect the data required under subpart W and 
has clarified the final rule to allow reporters to conduct an annual 
measurement of each compressor in the mode as it exists at the time the 
annual measurement is taken. EPA requires the development of emission 
factors from these measurements that reporters must apply appropriately 
to all compressors for the total time each compressor is operated in 
each mode. However, EPA requires that each compressor must be measured 
at least once during every 3-year period in the ``not operating and 
depressurized'' mode without blind flanges in place. Blind flanges are 
flat plates inserted between flanges on a valve or piping connection to 
assure absolute isolation of the equipment from process fluids, and 
hence, compromise through valve leakage measurement. Isolation valve 
leakage through the compressor blowdown vent, when the compressor is in 
the not operating and depressurized mode, must be measured before blind 
flanges are installed.
    Commenters suggested to EPA that based on their operational 
experience, 3 years is an appropriate maximum operational time period 
during which compressors will be shutdown for maintenance at least 
once, and therefore operators would not need to shutdown compressors 
specifically for the purposes of monitoring to gather measurements at 
this frequency. Accordingly, EPA is requiring reporters to schedule the 
measurement of compressors in the not operating and depressurized mode 
at least once during each consecutive 3-year time period.
    Comment: EPA received a broad range of comments that the 
methodologies for calculating GHG emissions in subpart W for specific 
emissions sources were too burdensome. Some commenters stated that 
quarterly sampling of produced natural gas to determine gas composition 
was overly burdensome and not necessary since produced gas composition 
does not change significantly from one quarter to the next. Other 
commenters suggested that requiring component counts for calculating 
equipment leaks for the onshore petroleum and natural gas industry 
segment was too onerous and time intensive since a reporter may have 
hundreds of wells across a large geographical area, and they currently 
do not have an inventory of all the components, such as valves, 
connectors and flanges, associated with their equipment. Several 
commenters stated that the number of tanks and dehydrators in the 
onshore petroleum and natural gas industry segment would be very 
burdensome to estimate emissions from using engineering equations. For 
example each tank would be required to obtain a sample analysis of low 
pressure separator oil for doing the engineering calculations. Finally, 
several commenters stated that the number of pneumatic devices and 
pneumatic pumps would require extensive time to determine the 
manufacturer model of each device in their facilities, and then 
estimate emissions based on manufacturer data.
    Lastly, commenters noted that compressor emissions measurement and 
compressor throughput flow was too burdensome, since many compressors 
would require the installation of expensive permanent meters.
    Response: EPA considered all of these comments, and performed 
extensive evaluation of the methodologies for calculating GHG emissions 
for each emissions source under each industry segment. EPA compared 
alternative methodologies that, when performed, would result in reduced 
burden on industry while maintaining the necessary quality of data to 
inform policy. Please see ``Alternative Methodologies'' Docket EPA-HQ-
OAR-2009-0923 for a full report of the analysis. Specifically, certain 
methodologies for specific emissions sources allowed for alternative 
methods that would reduce burden and maintain data quality. As a 
result, EPA determined that the following rule modifications would 
reduce burden while sustaining the necessary quality of data:

    <bullet> Individual component counts and population based 
emissions factors for onshore petroleum and natural gas production 
have been replaced with major equipment counts and default average 
component counts per primary equipment. Identification of primary 
equipment (dehydrators, compressors, heaters, etc.) will result in 
significantly less burden to reporters than counting each component 
(valve, flange, open-ended line, etc.).
    <bullet> Quarterly sampling of gas composition has been replaced 
with using your most recent representative gas analysis. Most 
onshore petroleum and natural gas producers would have this 
information already for transaction processing.
    <bullet> For onshore petroleum and natural gas production, for 
separators and well production with less than 10 barrels per day 
throughput and glycol dehydrators with less than 0.4 million 
standard cubic feet per day throughput, reporters will use emissions 
factors to determine emissions. Blowdown emissions from equipment 
vessel chambers totaling less than 50 cubic feet are not required to 
be reported. For more information, the following documents; 
``Equipment Threshold for Tanks,'' ``Equipment Threshold for 
Dehydrators,'' and ``Equipment Threshold for Blowdowns'' can be 
found in docket EPA-HQ-OAR-2009-0923.
    <bullet> For all pneumatic devices and pneumatic pumps in 
onshore petroleum and natural gas production and all pneumatic 
devices in onshore natural gas transmission compression facilities 
and underground natural gas storage facilities, reporters will 
utilize component counts and population emissions factors instead of 
engineering estimates. Note that onshore petroleum and natural gas 
production reporters must complete a total count of pneumatic 
devices any time within the first three calendar years. A reporter 
must report pneumatic device emissions annually. For any years where 
activity data (count of pneumatic devices) is incomplete, use best 
available data or engineering estimates to calculate pneumatic 
device emissions.
    <bullet> The final rule has clarified that emissions from 
centrifugal and reciprocating compressors do not require the 
installation of a permanent flow meter; use of a portable meter and 
port are acceptable. In addition, through-valve leakage to open 
ended vents, such as unit isolation valves on not operating 
depressurized compressors and blowdown valves on pressurized 
compressors, may be measured using acoustic leak detection devices. 
In addition, compressor throughput flow meters are not required; 
estimates of compressor flow will be sufficient for EPA's 
requirements.
4. Data Reporting Requirements
    Comment: Numerous commenters stated that there would be 
insufficient time, leak detection and measurement equipment, or service 
providers available to fully comply with subpart W reporting 
requirements. In particular, numerous onshore petroleum and natural gas 
production commenters expressed concern with the ability to gather data 
from geographically dispersed emissions sources starting January 1, 
2011. Also numerous commenters from the onshore natural gas processing 
and onshore natural gas transmission industry segments expressed their 
concern with their ability to comply with monitoring requirements, such 
as installing necessary measurement ports or meters for measurement.
    Response: As described below, EPA determined that for specified 
emissions sources for certain industry segments, some reporters may 
need more time to comply with the monitoring and QA/QC requirements of 
this subpart than by January 1, 2011. EPA carefully considered each 
source and the reporting compliance requirements and determined for 
which monitoring requirements it is appropriate to allow the use of 
best available monitoring

[[Page 74471]]

methods, for how long the use of best available monitoring methods will 
be applicable, and under what circumstances these methods are 
reasonable. EPA has extensively detailed when and how reporters may use 
best available monitoring methods specified in the following sections 
and in 40 CFR 98.234(f) of the rule.
    Best available monitoring methods are any of the following methods: 
monitoring methods currently used by the facility that do not meet the 
specifications of a relevant subpart; supplier data; engineering 
calculations; or other company records. Best available monitoring 
methods are available for three specific instances as well as providing 
a catch-all provision in the case of unanticipated issues or 
circumstances. In each category EPA determined the affected sources, 
reporting requirements and the time period necessary for owners or 
operators to implement the requirements of the rule. In all cases, the 
owner or operator must use the equations and calculation methods set 
forth in 40 CFR 98.233, but may use best available monitoring methods 
to estimate the parameters in the equations as specified in the 
following sections.
    EPA also carefully considered the timing for allowing application 
of best available monitoring methods. EPA determined the time duration 
for specified sources for which reporting entities may apply best 
available monitoring methods without a petition, and those for which 
reporting entities must request the use of best available monitoring 
methods. If the reporter anticipates the potential need for best 
available monitoring for sources for which they need to petition EPA 
and the situation is unresolved at the time of the deadline, reporters 
should submit written notice of this potential situation to EPA by the 
specified deadline for requests to be considered. EPA reserves the 
right to review petitions after the deadline but will only consider and 
approve late petitions which demonstrate extreme or unusual 
circumstances. Based on EPA's experience in implementing the 2009 final 
rule and those BAMM provisions, EPA made the source specific 
determinations for subpart W as outlined in the following sections.
    Well-Related Emissions Reporting. Subpart W requires the monitoring 
of well-related emissions sources for which the owner or operator must 
collect data during the actual event (for example, a well completion or 
workover conducted on a specific day in January 2011) and for which it 
may not be possible to collect or reproduce data after the event is 
over. EPA recognizes that a significant portion of well-drilling 
activities are conducted by third-party service providers and that in 
these cases, owners or operators may need to coordinate and possibly 
modify contracts, leases or other arrangements with service providers 
in order to gather data and thus it may not be possible for owners or 
operators to begin gathering well-related emissions data as of January 
1, 2011. For these sources EPA will allow the use of best available 
monitoring methods through June 30, 2011 to allow reporters sufficient 
time to meet the requirements of the rule.

    <bullet> Eligible Sources. There are three well-related sources 
for which subpart W requires emissions data collection at the time 
of the emissions event rather than at the reporter's discretion 
during a calendar year and for which use of best available 
monitoring methods will be allowed. These sources are as follows:

--Gas well workovers using hydraulic fracture in paragraph 40 CFR 
98.233(g)
--Gas well completions using hydraulic fracture in paragraph 40 CFR 
98.233(g)
--Well testing/flaring in paragraph 40 CFR 98.233(l)

    <bullet> Reporting Requirements. For the eligible sources 
listed, an owner or operator must use the equations prescribed in 40 
CFR 98.233(g) and 40 CFR 98.233(l) but may use best available 
monitoring methods to estimate any of the parameters. Best available 
monitoring methods may be:
--Monitoring methods currently used by the facility that do not meet 
the specifications of this subpart.
--Supplier data.
--Engineering calculations.
--Other owner or operator records.

    <bullet> Authorization to Use Best Available Monitoring Methods. 
All owners or operators may use best available monitoring methods 
for these sources between January 1, 2011 and June 30, 2011. Owners 
or operators do not have to submit a request to EPA for the initial 
six months. Owners or operators will have from the time this rule is 
signed by the Administrator until June 30, 2011 to make any 
necessary arrangements with service providers and other relevant 
organizations in order for the owner or operator to gather all 
necessary data to comply with subpart W. As this is approximately 
eight months time, starting July 1, 2011, EPA expects that owners or 
operators will have made arrangements or modified contracts with 
service providers, such as drilling companies, as necessary to 
comply fully with subpart W for these sources.
    <bullet> Requests for Extension in 2011. If additional time is 
necessary beyond June 30, 2011, an owner or operator must request an 
extension for use of best available monitoring methods by April 30, 
2011. In order to receive an extension for a time period between 
July 1, 2011 and December 31, 2011, owners and operators must 
provide the following information for each source covered under 40 
CFR 98.232(c)(6), 40 CFR 98.232(c)(8), and 40 CFR 98.232(c)(12):

--A list of the specific emissions sources within the owner or 
operator's facility for which the owner or operator is requesting an 
extension of best available monitoring methods.
--A description of the specific requirements in 40 CFR 98.233(g) and 
40 CFR 98.233(l) that the owner or operator cannot meet in 2011, 
including a detailed explanation as to why the requirements cannot 
be met.
--Supporting documentation such as the date of and copies of 
correspondence to service providers or other relevant entities 
whereby the owner or operator clearly requests that said service 
providers or other relevant entities provide required data.
--Demonstrate that it is not possible to obtain the necessary 
information, service or hardware which may include providing 
correspondence from specific service providers or other relevant 
entities to the owner or operator, whereby the service provider 
states that it is unable to provide the necessary data or services 
requested by the owner or operator that would enable the owner or 
operator to comply with subpart W reporting requirements.
--A detailed explanation and supporting documentation of how and 
when the owner or operator will receive the required data and/or 
services to comply with subpart W reporting requirements.

    The Administrator reserves the right to require additional 
documentation.
    EPA does not anticipate extending the use of best available 
monitoring methods beyond 2011 as approximately fourteen months will 
have passed since the Administrator's signature; however, under extreme 
and unique circumstances, which include safety, or a requirement being 
technically infeasible or counter to other local, State or Federal 
regulations, EPA may consider granting a further extension. Any such 
request must be received by September 30, 2011. The owner or operator 
must provide the following information in a request for the use of best 
available monitoring methods beyond 2011 for sources covered under 40 
CFR 98.232(c)(6), 40 CFR 98.232(c)(8), and 40 CFR 98.232(c)(12) for 
beyond 2011:

--A list of the specific emissions sources within the owner or 
operator's facility for which the owner or operator is requesting an 
extension of best available monitoring methods.
--A description of the specific requirements in 40 CFR 98.233(g) and 40 
CFR 98.233(l) that the owner or operator cannot meet, including a 
detailed explanation as to why the requirements cannot be met.
--Detailed outline of the unique circumstances necessitating an 
extension, including specific data collection issues that do not meet 
safety regulations, technical

[[Page 74472]]

infeasibility or specific laws or regulations that conflict with data 
collection for 40 CFR 98.232(c)(6), 40 CFR 98.232(c)(8), and 40 CFR 
98.232(c)(12). The owner or operator must consider all data collection 
options as outlined in the rule for a specific emissions source before 
claiming that a specific safety, technical or legal barrier exists. For 
example, if measuring an open-ended line on a rooftop does not meet 
safety regulations, companies must consider the use of portable meters 
using a port at ground-level.
--A detailed explanation and supporting documentation of how and when 
the owner or operator will receive the required data and/or services to 
comply with subpart W reporting requirements in the future.
    The Administrator reserves the right to require additional 
documentation.
    <bullet> It is the responsibility of the owner or operator to meet 
the reporting requirements of this rule. Accordingly, it is up to the 
owner or operator to best determine how they can obtain the necessary 
data to timely and fully comply.
    Stipulated Activity Data Collection. Several sources require the 
collection of activity data such as cumulative run time or a cumulative 
throughput volume to a piece of equipment starting January 1, 2011. 
Based on industry comments, EPA recognizes that it may not be feasible 
for an owner or operator to gather these data across all of their 
facilities as data collection in some cases must begin on January 1, 
2011. EPA has decided to allow reporters to use best available 
monitoring methods to estimate specific activity parameters used in the 
equations and methods outlined in 40 CFR 98.233 for the first six 
months of 2011. EPA will allow the use of best available monitoring 
methods for emissions sources for which the owner or operator must 
collect activity data sometime between January 1, 2011 and June 30, 
2011 and the owner or operator cannot reproduce or replicate the data 
after this time period. As owners or operators will have approximately 
eight months from the time of Administrator signature to June 30, 2011 
to develop systems to collect these data, EPA does not anticipate 
approving best available monitoring methods for collecting activity 
data after June 30, 2011.

    <bullet> Eligible Sources. Owners and operators may use best 
available monitoring methods only for the sources listed below:
--Cumulative hours of venting, days, or times of operation in 
paragraphs Sec.  98.233(e), (f), (g), (h), (l), (o), (p), (q), (r) 
of 40 CFR part 98.
--Number of blowdowns, completions, workovers, or other events in 
paragraphs Sec.  98.233(f), (g), (h), (i), and (w) of 40 CFR part 
98.
--Cumulative volume produced, volume input or output, or volume of 
fuel used in paragraphs Sec.  98.233(d), (e), (j), (k), (l), (m), 
(n), (x), (y), and (z) of 40 CFR part 98.
    <bullet> Reporting Requirements. For the sources eligible for 
best available monitoring methods applicable to stipulated activity 
data,, owners and operators must use the equations prescribed in 40 
CFR 98.233 but may use best available monitoring methods to estimate 
the stipulated activity parameters. Best available monitoring 
methods are:
--Monitoring methods currently used by the facility that do not meet 
the specifications of this subpart.
--Supplier data.
--Engineering calculations.
--Other owner or operator records.
    <bullet> Authorization to Use Best Available Monitoring Methods. 
All owners and operators may use best available monitoring methods 
for the sources eligible for best available monitoring methods 
applicable to stipulated activity data between January 1, 2011 and 
June 30, 2011. Owners or operators do not have to submit a request 
to EPA for the initial six months. As owners and operators will have 
approximately eight months from Administrator signature to June 30, 
2011, to prepare for the data collection requirements for the 
eligible sources, EPA expects that all owners or operators should 
have had adequate time to comply with the data collection 
requirements outlined in this subpart and therefore not need the use 
of best available monitoring methods for this information after June 
30, 2011.
    <bullet> Requests for Extension in 2011. Only under extreme 
circumstances, which include safety, or a requirement being 
technically infeasible or counter to other local, State, or Federal 
regulations, will EPA consider extending the use of best available 
monitoring methods for the collection of activity data through the 
end of 2011.
    <bullet> Owners or operators may submit a request for an 
extension through the end of 2011. These requests must be received 
by April 30, 2011 and include the following:
--A list of specific source categories and parameters for which the 
owner or operator is seeking use of best available monitoring 
methods.
--A description of the specific requirements in paragraphs Sec.  
98.233(e), (f), (g), (h), (i), (j), (k), (l), (m), (n), (o), (p), 
(q), (r), (w), (x), (y), and (z) of 40 CFR Part 98 that the owner or 
operator cannot meet, including a detailed explanation as to why the 
requirements cannot be met.
--Detailed outline of the unique circumstances necessitating an 
extension, including data collection methods that do not meet safety 
regulations, technical infeasibility or specific laws or regulations 
that conflict with the specific sources in this section of the 
preamble. The owner or operator must consider all data collection 
options as outlined in the rule for a specific emissions source 
before claiming that a specific safety, technical or legal barrier 
exists.
--A detailed explanation and supporting documentation of how and 
when the owner or operator will receive, for example, the services 
or equipment to comply with subpart W reporting requirements.

    The Administrator reserves the right to require additional 
documentation.
    <bullet> Requests for Extension beyond 2011. As approximately 
fourteen months will have passed between the Administrator's signature 
and December 31, 2011, EPA does not anticipate approving requests for 
best available monitoring methods beyond 2011 for applicable stipulated 
activity data sources eligible for best available monitoring methods; 
however, under extreme and unique circumstances, which include safety, 
a requirement being technically infeasible or counter to other local, 
State, or Federal regulations, it may consider granting a further 
extension. Any such requests for extensions beyond 2011 must be 
received by September 30, 2011 and include the following:
--A list of specific source categories and parameters for which the 
owner or operator is seeking use of best available monitoring methods.
--A description of the specific requirements in paragraphs Sec.  
98.233(e), (f), (g), (h), (i), (j), (k), (l), (m), (n), (o), (p), (q), 
(r), (w), (x), (y), and (z) of 40 CFR Part 98 that the owner or 
operator cannot meet, including a detailed explanation as to why the 
requirements cannot be met.
--Detailed outline of the unique circumstances necessitating an 
extension, including data collection methodologies that do not meet 
safety regulations, technical infeasibility or specific laws or 
regulations that conflict with sources outlined in this section of the 
preamble. The owner or operator must consider all data collection 
options as outlined in the rule for a specific emissions source before 
claiming that a specific safety, technical or legal barrier exists.
--A detailed explanation and supporting documentation of how and when 
the owner or operator will receive, for example, the services or 
equipment to comply with subpart W reporting requirements.
    The Administrator reserves the right to require additional 
documentation.
    Acquisition and implementation of leak detection and monitoring 
equipment or services. Based on industry comments, EPA understands that 
it may not be feasible for all owners or operators to acquire required 
leak detection and/or measurement equipment or hire a service provider 
in time to conduct the activities necessary

[[Page 74473]]

to complete leak detection and measurement requirements under subpart W 
within the 2011 calendar year. EPA will consider the use of best 
available monitoring methods for sources requiring leak detection and/
or measurement based on evidence provided by the owners or operators 
demonstrating that they have made all efforts but cannot obtain the 
necessary equipment or services in time to complete subpart W reporting 
in 2011.

    <bullet> Eligible Sources. With application approval from the 
Administrator, owners and operators may use best available 
monitoring methods only for the sources listed below:
--Reciprocating compressor rod packing vents for facilities 
downstream of onshore petroleum and natural gas production (i.e., 
onshore natural gas processing, onshore natural gas transmission 
compression, underground natural gas storage, LNG storage, and LNG 
import and export equipment) in 40 CFR 98.233(p).
--Centrifugal compressor wet seal oil degassing venting for 
facilities downstream of petroleum and natural gas production in 40 
CFR 98.233(o).
--Acid gas removal vents in 40 CFR 98.233(d).
--Equipment leaks in facilities downstream of onshore petroleum and 
natural gas production in 40 CFR 98.233(q).
--Transmission storage tanks in 40 CFR 98.233(k).
    <bullet> Reporting Requirements. For the sources eligible for 
best available monitoring methods applicable to acquisition and 
implementation of leak detection and monitoring equipment or 
services,, if approved by the Administrator, the owner or operator 
may use best available monitoring methods to estimate emissions and/
or the number of leaking components, and any throughputs, volumes, 
or maintenance records in place of the required monitoring methods 
outlined for parameters in 40 CFR 98.233. These best available 
monitoring methods are:
--Monitoring methods currently used by the facility that do not meet 
the specifications of this subpart.
--Supplier data.
--Engineering calculations.
--Other owner or operator records.
    <bullet> Authorization to Use Best Available Monitoring Methods. 
Because leak detection and/or measurement surveys are one-time 
actions that can be conducted at any time during the year, by April 
30, 2011, reporters must submit an application seeking approval for 
the use of best available monitoring methods. Upon approval by the 
Administrator, EPA may allow the use of best available monitoring 
methods for up to the entire 2011 calendar year. An owner or 
operator must submit this request no later than April 30, 2011 and 
include, at a minimum:
--A list of specific source categories and parameters for which the 
owner or operator is seeking use of best available monitoring 
methods.
--A description of the specific requirements in 40 CFR 98.233(d), 
98.233(k), 98.233(o), 98.233(p), and 98.233(q) that the owner or 
operator cannot meet and an explanation of how the owner or operator 
has diligently tried and why it cannot meet the requirements.
--Certification that the owner or operator does not already own 
relevant detection or measurement equipment.
--Documentation which demonstrates that the owner or operator made 
all reasonable efforts to obtain the service necessary to comply 
with subpart W reporting requirements in 2011, including evidence of 
specific service or equipment providers contacted and why services 
could not be obtained during 2011. EPA recognizes that some owners 
or operators may choose to conduct their own leak detection and 
measurement activities and therefore purchase equipment for that 
purpose. It is the owner or operator's responsibility to purchase 
all necessary equipment in time to meet 2011 reporting requirements. 
If relevant equipment vendors cannot deliver hardware in time for an 
owner or operator to meet subpart W requirements, the owner or 
operator must attempt to use outside service providers, prior to 
seeking a request for best available monitoring methodology 
extension.
--A detailed explanation and supporting documentation of how and 
when the owner or operator will receive the services or equipment to 
comply with subpart W reporting requirements in 2012.

    The Administrator reserves the right to require additional 
documentation.
    <bullet> Requests for Extension. As owners and operators will have 
had approximately fourteen months since the date of the Administrator's 
signature and December 31, 2011, EPA does not anticipate extending best 
available monitoring methods beyond 2011; however, under extreme and 
unique circumstances, which include safety, or a requirement being 
technically infeasible or counter to other local, State, or Federal 
regulations, EPA may consider granting a further extension. Any such 
request for extensions beyond 2011 must be received by September 30, 
2011 and include the following:
--A list of specific source categories and parameters for which the 
owner or operator is seeking use of best available monitoring methods.
--A description of the specific requirements in 40 CFR 98.233(d), 
98.233(k), 98.233(o), 98.233(p), and 98.233(q) for which extension is 
being requested and of the unique circumstances necessitating an 
extension, including specific data collection methodologies that do not 
meet safety regulations, technical infeasibility or specific laws or 
regulations that conflict with sources outlined in this section of the 
preamble. The owner or operator must consider all data collection 
options as outlined in the rule for a specific emissions source before 
claiming that a specific safety, technical or legal barrier exists.
--Detailed explanation and supporting documentation of how and when the 
owner or operator will receive the services or equipment to comply with 
subpart W reporting requirements.
    The Administrator reserves the right to require additional 
documentation.
Unique or Extreme Circumstances
    <bullet> Requests for 2011: Emissions sources not covered under the 
previous three categories of BAMM are under operational control of the 
owner or operator, require one time data collection at any point during 
the calendar year and do not require leak detection or measurement 
equipment. For these reasons, for the sources not covered under the 
previous three categories of BAMM, EPA does not anticipate the need for 
best available monitoring methods; however, EPA will review all 
requests submitted by April 30, 2011 and consider approval of the use 
of best available monitoring methods for 2011 under unique and extreme 
circumstances, which include safety, or requirement being technically 
infeasible or counter to other local, State, or Federal regulations. 
Requests for the use of best available monitoring methods for sources 
not covered under the previous three categories of BAMM must include:
--A list of specific source categories and parameters for which the 
owner or operator is seeking use of best available monitoring methods.
--Detailed outline of the unique circumstances necessitating an 
extension, which must include data collection methodologies that do not 
meet safety regulations, technical infeasibility or specific laws or 
regulations that conflict with specific sources for which owners or 
operators are requesting best available monitoring methods. The owner 
or operator must consider all data collection options as outlined in 
the rule for a specific emissions source before claiming that a 
specific safety, technical or legal barrier exists.
--A detailed explanation and supporting documentation of how and when 
the owner or operator will receive the services or equipment to comply 
with subpart W reporting requirements in 2012.
    The Administrator reserves the right to require additional 
documentation.
    <bullet> Requests beyond 2011: For sources not covered in the 
previous three categories of BAMM, EPA does not anticipate the need for 
best available monitoring methods beyond 2011;

[[Page 74474]]

however, EPA will review such requests submitted by September 30, 2011 
and consider approval of the use of best available monitoring methods 
for 2012 under unique and extreme circumstances, which include safety, 
or a requirement being technically infeasible or counter to other 
local, State, or Federal regulations. Requests for the use of best 
available monitoring methods for sources not covered in the previous 
three categories of BAMM, must include:
--A list of specific source categories and parameters for which the 
owner or operator is seeking use of best available monitoring methods.
--Detailed outline of the unique circumstances necessitating an 
extension, which must include data collection methodologies that do not 
meet safety regulations, technical infeasibility or specific laws or 
regulations that conflict with specific sources for which owners or 
operators are requesting best available monitoring methods. The owner 
or operator must consider all data collection options as outlined in 
the rule for a specific emissions source before claiming that a 
specific safety, technical or legal barrier exists.
--A detailed explanation and supporting documentation of how and when 
the owner or operator will receive the services or equipment to comply 
with subpart W reporting requirements.

The Administrator reserves the right to require additional 
documentation.
5. Legal Authority
    Comment: Several commenters asserted that EPA is over-reaching its 
CAA 114 authority. These commenters specifically stated that CAA 
section 114 does not authorize EPA to require indefinite and sweeping 
monitoring, recordkeeping, and reporting from the facilities covered by 
proposed subpart W. On the other hand, several commenters asserted that 
the proposal was within EPA's authority under the CAA.
    Response: As explained in Section I.C. of this preamble, Section 
I.C and Q of the 2009 final Part 98 preamble (74 FR 56260), and the 
document Mandatory Greenhouse Gas Reporting Rule: EPA's Response to 
Public Comments, Volume 9, Legal Issues (EPA-HQ-OAR-2008-0508), EPA is 
promulgating subpart W under its existing CAA authority provided in CAA 
section 114. EPA disagrees with the commenters that it does not have 
statutory authority to require monitoring, reporting and recordkeeping 
from facilities in the petroleum and natural gas systems source 
category. The Administrator may gather information under CAA section 
114, as long as that information is for purposes of carrying out any 
provision of the CAA. For example, CAA section 103 authorizes EPA to 
establish a national research and development program, including non-
regulatory approaches and technologies, for the prevention and control 
of air pollution, including GHGs. The data collected under this rule 
will also inform EPA's implementation of CAA section 103(g) regarding 
improvement in sector based non-regulatory strategies and technologies 
for preventing or reducing air pollutants. For more information about 
EPA's legal authority please see the related sections and documents in 
the preamble for subpart W.
6. Designated Representative
    Comment: Several commenters stated that EPA lacked the authority to 
require facilities to collect data on equipment and activities that may 
be operated or provided by a third party service provider and then 
require a designated representative to certify those emissions data. 
Other commenters supported the inclusion of emissions data from 
equipment operated by third party service providers by stating that 
these emissions are critical to ensuring that facilities with different 
operational structures have equitable coverage in a reporting program 
and that a complete profile of emissions from the production sector is 
obtained.
    Response: As explained in Section V of the preamble of the 2009 
final part 98 (74 FR 56355), all reporters must select a designated 
representative (DR) who is responsible for certifying, signing, and 
submitting all submissions to EPA. This provision provides flexibility 
to the owners and operators to choose any individual, employee or non-
employee, to represent them, while ensuring EPA has one accountable 
point of contact. As explained in the preamble to the final part 98, 
the high level of public interest in the data collected, as well as its 
importance to future policy, warrants establishment of a high standard 
for data quality and consistency and high level of accountability for 
reported data. The DR provisions and certification requirements help 
ensure the standard for high quality data and consistency is met. The 
DR provisions are crafted similarly to the provisions of the Acid Rain 
Program (ARP), 40 CFR part 72 and EPA has found that this approach 
provides a high degree of both data quality and consistency and 
accountability.
    Similar comments were made about the data coming from multiple 
owners and operators and the concerns about the certification of those 
data upon promulgation of the ARP and the 2009 final GHG reporting rule 
to which we responded, and for which responses are summarized. We have 
attempted to provide maximum flexibility while ensuring accountability. 
For integrity of the program, one representative of the owners and 
operators must report for important reasons. Doing so ensures the 
accountability of owners or operators by, inter alia, reducing the 
likelihood of inconsistent submissions by a facility. Interposing 
another person or party between the facility and the Agency would 
dilute the DR's responsibility and in effect create multiple DRs for 
the facility. Additionally, leaving the ultimate responsibility of 
submission with the designated representative has the salutary effect 
of clarifying that the DR should be aware of all submissions and should 
inquire of the persons with personal knowledge of the information in 
those submissions. The DR has the flexibility to delegate duties, such 
as the preparation of submissions, but retains the ultimate 
responsibility to sign and certify all submissions. (See, 58 FR 3590, 
3598, January 11, 1993.)
    Furthermore, while the DR or his delegatee may need to acquire 
necessary reporting information from a third party, the DR must make 
the appropriate inquiries and certification when reporting; ultimate 
responsibility rests and must necessarily rest on him or her. The DR 
may provide in contracts, leases, or other agreements with third 
parties that true, accurate, and correct reporting information must be 
provided to the DR in a timely fashion. If the third party fails to 
provide timely, true, accurate, or correct information to the DR, then 
the DR has recourse contractually, or otherwise, on the third party. 
Finally, in recognition of their potential need to adjust contracts, 
leases, or agreements accordingly, additional flexibility has been 
provided in the rule to allow facilities to utilize best available 
monitoring methods for a limited period. For more information, see 
Section V of the preamble to the 2009 final Part 98 (74 FR 56260) and 
the document Mandatory Greenhouse Gas Reporting Rule: EPA's Response to 
Public Comments, Volume 11, Designated Representative and Data 
Collection, Reporting, Management and Dissemination (EPA-HQ-OAR-2008-
0508).
7. Applicability
    Comment: Multiple commenters requested that EPA develop a set of

[[Page 74475]]

screening tools to assist in the determination of which entities would 
be required to report under subpart W of 40 CFR part 98.
    Response: Similar to what EPA has already provided for other 
subparts of the Greenhouse Gas Reporting Program to help reporters 
assess the applicability of the Greenhouse Gas Reporting Program \5\ to 
their facilities, EPA plans to develop voluntary screening tools for 
the petroleum and natural gas source category. EPA anticipates that 
such tools would be based on easily determined inputs such as major 
equipment or operational counts. While the tools would be designed to 
provide help to potential reporters for complying with the rule, 
compliance with all Federal, State, and local laws and regulations 
remain the sole responsibility of each facility owner or operator 
subject to those laws and regulations. The tools would be a guide to 
determine those facilities that are clearly well below the reporting 
threshold, those clearly above, and those close to the threshold who 
will need to collect further data to make a proper determination.
---------------------------------------------------------------------------

    \5\ http://www.epa.gov/climatechange/emissions/GHG-calculator/index.html.
---------------------------------------------------------------------------

III. Economic Impacts of the Rule

    This section of the preamble summarizes the costs and economic 
impacts of the final subpart W rulemaking, including the estimated 
costs and benefits of subpart W, and the estimated economic impacts on 
affected facilities, including estimated impacts on small entities. 
Complete details of the economic impacts of the final subpart W rule 
can be found in the Economic Impact Analysis (EIA) in the rulemaking 
docket (EPA-HQ-OAR-2009-0923).
    This section also contains a brief summary of major comments and 
responses on the economic impacts of the rule. EPA received a number of 
comments on the estimated compliance costs as well as other comments 
covering a variety of topics. Responses to significant comments can be 
found in Mandatory Greenhouse Gas Reporting Program: EPA's Response to 
Public Comments, Cost and Economic Impacts of the Rule, Docket EPA-HQ-
OAR-2008-0508.

A. How were compliance costs estimated?

1. Summary of Method Used To Estimate Compliance Costs of the Final 
Rule
    EPA estimated costs for each affected petroleum and natural gas 
industry facility to comply with subpart W. These estimates capture the 
costs associated with monitoring and reporting both equipment leaks and 
vented emissions and incremental combustion-related emissions.\6\ EPA 
based the estimates on the number of labor hours to perform specific 
activities, the cost of labor, and the cost of monitoring equipment.
---------------------------------------------------------------------------

    \6\ Reporting entities that equal or exceed the subpart W 
threshold for equipment leak and vented emissions must report 
combustion emissions under subpart C, except for onshore production 
and LDCs, which must report combustion emissions under subpart W. 
Incremental combustion emissions refer to those from entities that 
did not trigger the subpart C threshold in the absence of subpart W.
---------------------------------------------------------------------------

    The costs of complying with the rule will vary from one petroleum 
and gas industry segment and facility to another, depending on factors 
such as the types of emissions, the number of affected sources at the 
facility and existing maintenance practices, monitoring, recordkeeping, 
and reporting activities at the facility. The costs include 
expenditures related to monitoring, recording, and reporting process 
emissions and, as relevant, emissions from stationary combustion.
    Staff activities and associated labor costs may also vary over 
time. In particular, start-up activities, such as the installation of 
ports for compressors to allow for spot measurements, result in notably 
higher costs in the first year. Costs would also vary over time when 
site-specific emissions factors are developed every 2 or 3 years. Thus, 
EPA developed cost estimates for year one, which include start-up and 
first-time reporting, and for subsequent year reporting.
    EPA estimated annual costs in 2006 dollars using the 2006 
population of emitting sources. In addition, the agency estimated costs 
on a per entity basis and weighted them by the number of entities 
affected at the 25,000 metric tons CO<INF>2</INF>e threshold.
    To develop compliance cost estimates, EPA gathered existing data 
from EPA studies and publications, industry trade associations and 
publicly available data sources (e.g., labor rates from the Bureau of 
Labor Statistics) to characterize the processes, sources, segments, 
facilities, and companies/entities affected. EPA also considered cost 
data submitted in public comments on the proposed rule.
    Next, 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 data that are already being collected for 
reasons not associated with the rule (to allow only the incremental 
costs to be estimated).
    Labor Costs. The costs of complying with and administering this 
rule include time of managers, and of technical, operational and 
administrative staff in the private sector. Staff hours were estimated 
for activities, including:

    <bullet> Developing a plan: Reporting entity management, legal, 
and technical staff hours to determine applicability of the rule, 
organize training on rule requirements, identify staffing 
assignments, train staff, and schedule activities as required below.
    <bullet> Setting up records: Technical and field staff hours to 
develop data collection sheets and analytical model equations or 
linkages to input data into software programs.
    <bullet> Collecting field data: Technical and field staff hours 
to collect necessary site-specific data and input that data into the 
analytical input tables.
    <bullet> Monitoring: Staff hours to procure, install, operate 
and maintain emissions monitoring equipment, instruments and 
engineering analysis systems.
    <bullet> 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.
    <bullet> Recordkeeping: 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.
    <bullet> Reporting: Management and staff hours to organize data, 
perform quality assurance/quality control, inform key management 
personnel, and report it to EPA through electronic systems.

    Estimates of labor hours were based on economic analyses 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. See the Economic 
Impact Analysis for the Mandatory Reporting of Greenhouse Gas Emissions 
Under Subpart W Final Rule (EPA-HQ-OAR-2009-0923) for a detailed 
discussion about the engineering analysis used to develop these 
estimates. In addition, 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.
    EPA monetized the labor hours using wage rates from the Bureau of 
Labor Statistics (BLS). The agency also adjusted the wage rates to 
account for overhead.

[[Page 74476]]

    Equipment Costs. Equipment costs include both the initial purchase 
price of monitoring equipment and installation cost. 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 cost 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 5-year cost recovery period at a rate of seven percent. Not all 
segments require monitoring equipment capital expenditures but those 
that do are clearly documented in the Economic Impact Analysis.
    Incremental Combustion Costs. EPA estimated the costs to monitor 
and report incremental combustion emissions, which are combustion-
related emissions from entities that did not trigger the subpart C 
threshold in the absence of subpart W. As discussed earlier in this 
section, reporting entities that equal or exceed the subpart W 
threshold must report combustion emissions following the methods under 
subpart C, except for onshore production entities that consume field 
gas or process vent gas and LDCs, which must report combustion 
emissions following the methods under subpart W.
    For purposes of cost estimation, EPA determined that under the 
final rule, entities that need to report incremental combustion-related 
emissions, as previously defined, would likely use either the Tier 1 
calculation methodology as set forth in subpart C or the calculation 
methodology as set forth in subpart W (40 CFR 98.233(z)). EPA 
determined that the entities reporting incremental emissions under 
subpart C would likely not meet the requirements for Tier 2 or higher 
methods. However, as these entities will be reporting combustion 
emissions under subpart C (except onshore production and LDCs), if a 
facility did meet the requirements for a tier other than Tier 1, the 
facility would have to use the required method, as specified in subpart 
C.
    Given that the combustion methodology in 40 CFR 98.233(z) is 
similar to the Tier 1 calculation methodology, EPA estimated the costs 
to monitor and report incremental combustion-related emissions based on 
the approach used under 40 CFR part 98, subpart C.\7\ Specifically, EPA 
applied the Tier 1 calculation methodology to estimate the costs to 
monitor combustion emissions that became subject to reporting as a 
result of this final action. The Tier 1 approach bases estimates on a 
fuel-specific default CO<INF>2</INF> emission factor, a default high 
heating value of the fuel, and the annual fuel consumption from company 
records.
---------------------------------------------------------------------------

    \7\ 40 CFR part 98 uses the IPCC Tier concept to estimate 
combustions emissions (74 FR 56260, October 30, 2009). See EPA-HQ-
OAR-2008-0508-0004, U.S. EPA, Technical Support Document for 
Stationary Fuel Combustion Emissions: Proposed Rule for Mandatory 
Reporting of Greenhouse Gases, January 30, 2009, for more 
information about the IPCC Tier methodology (pgs 10-15).
---------------------------------------------------------------------------

    EPA based its conclusion that entities would likely report 
incremental combustion emissions using the Tier 1 method on three 
considerations for applicability of the Tier 2 calculation methodology 
and higher, as specified in subpart C, to the petroleum and natural gas 
industry: (1) Availability of high heating values (HHVs) for the fuels 
combusted at the frequency required by the Tier 2 calculation 
methodology, (2) the maximum rated heat capacity of the equipment, and 
(3) the type of fuel being combusted. First, in order to be allowed to 
use a Tier 2 analysis, units must have a rated heat capacity less than 
or equal to 250 mmBtu/hr, combust a fuel found in Table C-1 of subpart 
C, and sample the HHV of the fuel consumed at the required frequency in 
40 CFR 98.34(a). It was determined that this minimum required sampling 
frequency is not currently carried out at these smaller units and 
therefore these units would not be required to use Tier 2 methodology. 
These units will generally follow Tier 1 methodology.
    Second, Tier 3 and Tier 4 calculation methodologies generally apply 
to equipment with a maximum rated heat capacity greater than 250 mmBtu/
hr. A 250 mmBtu/hr rating means that the emissions from that individual 
unit alone will be greater than 25,000 metric tons CO<INF>2</INF>e; 
these emissions would be subject to reporting under subpart C even in 
the absence of subpart W and therefore would not fall in the category 
of incremental combustion emissions considered in this analysis.
    Third, the predominant fuels used in the petroleum and natural gas 
industry are produced natural gas, pipeline quality natural gas, 
distillate fuel, and any products recovered from equipment leaks and 
vents. The use of produced natural gas is predominant in onshore 
petroleum and natural gas production. Under the final rule for subpart 
W, reporters in this segment are allowed to use methods similar to Tier 
1 for all combustion emissions sources that use produced natural gas.
    In the remaining segments, equipment using produced natural gas or 
products recovered from equipment leaks and vents are normally required 
to use Tier 2 methodology or higher. However, as described previously, 
if the unit has a rated heat capacity less than or equal to 250 mmBtu/
hr, then the unit probably does not currently receive HHV at the 
required frequency for a Tier 2 analysis and could use a Tier 1 
analysis instead. If the unit has a maximum rated heat capacity greater 
than 250 mmBtu/hr, then as just noted, emissions from a unit of this 
size would already be subject to reporting under subpart C and would 
not be included in the incremental combustion emissions category 
considered in this analysis. In sum, the use of Tier 1 methodology for 
incremental combustion is a reasonable assumption for costing the 
subpart W rule.
    Reporting Determination Costs. Facilities will have to estimate 
their emissions to determine whether they exceed the reporting 
threshold. The costs for making a reporting determination includes 
primarily the use of screening tools, which EPA plans to develop. The 
costs also account for cases in which preliminary monitoring is also 
required to make a reporting determination.
2. Summary of Comments and Responses
    EPA received many comments on the method used to estimate the 
rule's compliance costs. Nearly all of these comments focused on both 
the methodology and the resulting cost estimates. Therefore, a summary 
of these comments and EPA's response is presented in the next section 
of this preamble, Section III.B.2, What are the costs of the rule? For 
the detailed responses to all comments received, see Mandatory 
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, 
Subpart W: Petroleum and Natural Gas Systems (EPA-HQ-OAR-2009-0923).

B. What are the costs of the rule?

1. Summary of Costs
    Table 6 of this preamble presents for each segment the total costs 
and costs per ton in the first year and subsequent years as well as the 
annualized costs. EPA estimates that the total private sector cost in 
the first year is about $62 million and about $19 million for 
subsequent years; the annualized cost over a 20-year time period is 
about $21 million (3 percent discount rate) and $22 million (7 percent 
discount rate) (2006$). Of these costs, EPA estimates

[[Page 74477]]

roughly $40 million to report process emissions in the first year and 
about $15 million in subsequent years. In addition, EPA estimates 
approximately $3 million to report incremental combustion related 
emissions in both the first year and in the subsequent years.
    The reporting threshold determines the number of entities required 
to report GHG emissions and hence the costs of the rule. The number of 
entities excluded increases with higher thresholds. Table 7a and Table 
7b of this preamble provide the cost-effectiveness analysis for various 
thresholds examined. Two metrics are used to evaluate the cost-
effectiveness of the emissions threshold. The first is the average cost 
per metric ton of emissions reported ($/metric ton CO<INF>2</INF>e). 
The second metric for evaluating the threshold option is the 
incremental cost per metric ton of emissions reported. The incremental 
cost is calculated as the additional (incremental) cost per metric ton 
using 25,000 metric tons CO<INF>2</INF> equivalent as the baseline. For 
more information about the first year capital costs (unamortized), 
project lifetime and the amortized (annualized) costs for each 
petroleum and gas industry segment please refer to Section 4 of the 
Economic Impact Analysis for the final subpart W.

                                         Table 6--National Cost Estimates for Petroleum and Natural Gas Systems
                                                                       [2006$] \1\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                     First year                          Subsequent year
                                       ----------------------------------------------------------------------------  Annualized  cost   Annualized  cost
                Segment                   National  cost    Cost  ($/metric     National  cost    Cost  ($/metric        (3%) \2\           (7%) \3\
                                            ($million)            ton)            ($million)            ton)            ($million)         ($million)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Processing............................               8.13               0.26               2.10               0.07               2.43               2.57
Transmission..........................              16.87               0.40               6.49               0.15               7.02               7.26
Underground Storage...................               2.73               0.35               1.02               0.13               1.10               1.14
LNG Storage...........................               0.70               0.41               0.26               0.15               0.28               0.29
LNG import/export.....................               0.14               0.44               0.03               0.09               0.04               0.04
LDC...................................               3.31               0.15               1.35               0.06               1.47               1.52
Onshore Production....................              26.58               0.12               7.54               0.03               8.61               9.05
Offshore Production...................               3.33               0.65               0.24               0.05               0.42               0.49
                                       -----------------------------------------------------------------------------------------------------------------
    Total (8 Segments)................              61.78               0.18              19.01               0.06              21.36              22.34
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Includes determination costs for non-reporters. These estimates are conservative and should be viewed as an upper-bound because the determination
  costs were applied at the facility-level rather than the company-level. For example, for offshore production, determination costs were applied to each
  of the approximately 3,000 platforms in the Gulf of Mexico rather than the 86 operators in that region. See the memo, ``Estimates of Determination
  Costs,'' in the docket for complete details and additional determination cost estimates (EPA-HQ-OAR-2009-0923).
\2\ The cost to report annualized over 20 years at 3 percent (see additional details in section 5 of the EIA for the final rule).
\3\ The cost to report annualized over 20 years at 7 percent (see additional details in section 5 of the EIA for the final rule).


                                                     Table 7A--Threshold Cost-Effectiveness Analysis
                                                                   [First Year, 2006$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                          Percentage  of
                                                        Facilities                         Downstream          total          Average       Incremental
            Threshold (metric tons CO2e)                required to    Total costs \1\      emissions       downstream       reporting     cost  ($/Mt)
                                                          report      (million  2006$)      reported         emissions     cost  ($/Mt)        \1,2\
                                                                                          (MtCO2e/year)      reported           \1\
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000...............................................          12,622           $148.67               391             99%           $0.38           $1.62
10,000..............................................           4,400             79.01               362             91%            0.22            0.69
25,000..............................................           2,786             61.78               337             85%            0.18            0.00
100,000.............................................           1,062             44.32               273             69%            0.16          (0.27)
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Includes determination costs for non-reporters. The upper-bound first-year determination cost estimates for each threshold are as follows: 1,000
  metric tons CO2e = $12.3 million; 10,000 metric tons CO2e = $17.4 million; 25,000 metric tons CO2e = $18.4 million; and 100,000 metric tons CO2e =
  $19.3 million. As noted in previous table, these estimates are conservative. See the memo, ``Estimates of Determination Costs,'' in the docket for
  complete details and additional determination cost estimates (EPA-HQ-OAR-2009-0923).
\2\ Cost per metric ton relative to the selected option (25,000 MT threshold).


                                                     Table 7B--Threshold Cost-Effectiveness Analysis
                                                                [Subsequent Year, 2006$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                          Percentage  of
                                                        Facilities                         Downstream          total          Average       Incremental
           Threshold  (metric  tons  CO2e)             required  to   Total  costs \1\      emissions       downstream       reporting       cost  ($/
                                                          report       (million $2006)      reported         emissions     cost  ($/Mt)      Mt)\1, 2\
                                                                                          (MtCO2e/year)      reported           \1\
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000...............................................          12,622            $73.44               391             99%           $0.19           $1.02
10,000..............................................           4,400             30.51               362             91%            0.08            0.46
25,000..............................................           2,786             19.01               337             85%            0.06            0.00

[[Page 74478]]

 
100,000.............................................           1,062              9.77               273             69%            0.04          (0.14)
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Includes determination costs for non-reporters. The upper-bound determination costs in subsequent years for each threshold are as follows: 1,000
  metric tons CO2e = $1.8 million; 10,000 metric tons CO2e = $1.0 million; 25,000 metric tons CO2e = $0.6 million; and 100,000 metric tons CO2e = $0.2
  million. As noted in previous table, these estimates are conservative. See the memo, ``Estimates of Determination Costs,'' in the docket for complete
  details and additional determination cost estimates (EPA-HQ-OAR-2009-0923).
\2\ Cost per metric ton relative to the selected option (25,000 MT threshold).

2. Summary of Comments and Responses
    Overview. EPA received extensive comments on the methodology and 
cost data presented in the Economic Impact Analysis for the proposed 
subpart W (EPA-HQ-OAR-2009-0923-0020). The comments can be sorted into 
two major categories: (1) Comments on the costs for facilities to make 
a reporting determination, and (2) comments on cost estimates of labor 
and equipment for certain industry segments to monitor and report 
emissions.
    Reporting Determination. Commenters stated that EPA's analysis 
underestimated the true compliance burden by omitting the costs for 
facilities to make a reporting determination--i.e., estimate annual 
emissions to determine whether they meet the reporting threshold. These 
commenters recommended that EPA account for reporting determination 
costs incurred by both facilities that report as well as non-reporters, 
i.e., those that monitor emissions but do not meet the reporting 
threshold. As discussed in Section II.F.6 of this preamble, the 
commenters also recommended that EPA develop screening tools to reduce 
the burden for facilities to make a reporting determination.
    EPA agrees with commenters that the EIA would better reflect the 
rule's total economic burden by including all reporting determination 
costs. While EPA's compliance cost estimates accounted for the 
reporting determination burden in the proposal, it did not include the 
determination burden for non-reporters. Therefore, EPA has estimated 
the burden for reporting determinations made by non-reporters and 
included it in the EIA for the final rule. EPA based this estimate on 
the assumption that non-reporters will use a screening tool, which EPA 
intends to provide to facilitate reporting determinations. The 
estimated total cost for all non-reporters to make a reporting 
determination is about $18.4 million, which accounts for use of the 
screening tool and, if required, the cost to conduct further screening; 
Section 4 of the EIA provides a complete discussion of the basis for 
this estimate.\8\ EPA expects use of the screening tool to minimize 
burden by allowing facilities to enter basic activity data, such as 
well count and drilling activity, into the tool to roughly assess 
whether they meet the threshold. Facilities for which the tool 
estimates emissions well below the threshold will generally not need to 
conduct further screening. Facilities for which the tool estimates 
emissions near the threshold will generally conduct additional 
screening, and this is reflected in the cost estimates.
---------------------------------------------------------------------------

    \8\ These estimates are conservative and should be viewed as an 
upper-bound because the determination costs were applied at the 
facility-level rather than the company-level. For example, for 
offshore production, determination costs were applied to each of the 
approximately 3,000 platforms in the Gulf of Mexico rather than the 
86 operators in that region. See the memo, ``Estimates of 
Determination Costs,'' in the docket for complete details and 
additional determination cost estimates (EPA-HQ-OAR-2009-0923).
---------------------------------------------------------------------------

    Labor and Equipment Costs. Many commenters disagreed with EPA's 
cost estimates in particular segments and presented alternative 
estimates that in some cases differed from the agency's estimates by 
orders of magnitude. Many of the comments suggested that EPA's 
estimates of labor costs (e.g., number of labor hours required to 
collect field data, to use equipment and engineering analysis systems 
to measure emissions, and to manage the emissions data) and equipment 
costs (e.g., purchase of flow meters) were too low.
    In development of this rule and in response to comments, EPA 
collected and evaluated cost data from multiple sources, closely 
reviewed the input received through public comments, and weighed the 
analysis prepared against this input. EPA also carefully weighed the 
burden of incrementally more comprehensive methods of measuring and 
calculating emissions against the increase in coverage and accuracy, 
and in some cases revised or clarified the measurement and calculation 
requirements. EPA has thus adjusted both the rule requirements and its 
cost estimates in response to comments, and concludes that its 
methodology and final cost estimates appropriately account for the 
compliance burden under this final rule. EPA determined that the 
commenters' alternative estimates are much higher than the agency's 
because of assumptions and interpretations that were either 
inconsistent with EPA's original intent (and which EPA has now 
clarified) or requirements that have been revised; in some cases, the 
alternative estimates were also based on higher-cost, optional 
monitoring methods.
    EPA summarizes below the key assumptions, revisions, 
misinterpretations, and use of higher-cost, optional methods and the 
resulting costs estimates that differed most from EPA's estimates. 
These comments were concentrated in three industry segments: (1) 
Onshore production, (2) natural gas processing, and (3) natural gas 
distribution segments.
3. Onshore Production
    Comment: Commenters stated that EPA's estimated compliance costs 
for the onshore petroleum and natural gas production segment were too 
low. Overall, the commenters concluded that EPA should reassess the 
analysis of entities covered by the rule, the assumptions underlying 
the cost estimates, and reduce the monitoring and reporting burden.
    One commenter provided detailed, alternative cost estimates and 
concluded that costs could be as high as $1.8 billion for the onshore 
production segment in the first year, which is notably higher than 
EPA's proposal estimate of $30.4 million for this segment. The 
commenter made various assumptions that differed from EPA's analysis 
and accounted for the difference in the cost estimates. One

[[Page 74479]]

source of the difference stemmed from the estimate of the number of 
sources in the onshore production segment subject to monitoring. 
Specifically, the commenter assumed that because the proposed rule 
would cover about 80 percent of emissions from the petroleum and gas 
industry, approximately 80 percent of the sites and equipment at each 
onshore production facility would be subject to the rule. The commenter 
therefore concluded that the rule would cover 80 percent of the 823,000 
wells in the nation, or about 667,000 wells, which exceeds EPA's 
estimated coverage of about 467,000 wells, plus sources at non-well 
sites.\9\ In particular, the commenter said that counting components to 
estimate emissions from equipment leaks would be onerous.
---------------------------------------------------------------------------

    \9\ Commenter estimated 823,000 wells based on a ``US Energy 
Information Administration's 2008 report,'' but did not provide any 
other citation information.
---------------------------------------------------------------------------

    Additional differences in the commenter's and EPA's estimates 
resulted from differences in the assumptions about labor wages and time 
spent sampling. For example, the commenter presented a breakdown of the 
labor and equipment costs, such as labor wages and time spent on 
sampling activities. Sampling activities accounted for a notable 
fraction of the commenter's estimates. For example, the commenter 
estimated costs for sampling activity to determine the composition of 
produced natural gas and low pressure separator oil and to analyze all 
tanks for hydrocarbon liquids and produced water.
    In addition, data management software constituted a substantial 
fraction of the commenter's total cost estimate. The commenter stated 
that individual reporters would spend between $100,000 and $850,000 for 
data management software, which totals to approximately $123 million to 
$1 billion for the entire segment.
    EPA has carefully reviewed these comments and disagrees that the 
true costs will be substantially higher than those estimated by the 
agency.
    First, EPA disagrees with the commenter's estimate of the number of 
sources subject to reporting because it incorrectly assumed that the 
proposed rule covered 80 percent of all wells in the United States. The 
commenter's assumption that each reporter would need to monitor 80 
percent of its wells in order to report about 80 percent of its 
emissions implies that the type and quantity of emissions from each 
well are identical. This assumption, which resulted in much more labor 
and complex monitoring than required under the proposal, is incorrect. 
The quantity and type of emissions from wells are variable; in fact, it 
is not necessary to monitor 80 percent of wells to account for 80 
percent of emissions and neither the proposed nor final rules would 
require such a large percentage of wells to be covered. Because the 
final rule tends to target those wells that have the higher emissions, 
based on its threshold analysis, EPA estimates that approximately 60 
percent of the wells are subject to the monitoring requirements, and 
that these wells will account for about 85 percent of total GHG 
emissions from this segment.
    EPA conducted the threshold analysis using actual data available 
through the commercial database from HPDI LLC, which collects these 
data primarily from individual petroleum and natural gas producing 
States that require petroleum and natural gas producing companies to 
report field data. The HPDI database includes operator well count. In 
most cases, HPDI provides data for each well on the production of 
petroleum and natural gas by operator and basin; some data are listed 
by property, which is a collection of wells. EPA developed a reasonable 
estimate of the emissions per well by apportioning the national 
emissions from each emissions source type to each of the wells based on 
the contribution of petroleum and natural gas production from each well 
to the national total. This analysis suggests that approximately 60 
percent of the wells are owned or operated by entities that would 
trigger the reporting threshold, not 80 percent.
    The commenter's analysis of the onshore production burden also 
incorrectly assumed that the rule required all onshore production 
reporters to spend up to $1 billion on data management software. EPA 
disagrees with this assumption. EPA notes that the rule does not 
require reporters to purchase data collection software. It is at the 
reporters' discretion to do so.
    Although the commenter did not provide any information about the 
software represented in its analysis (except for cost), a system in the 
price range assumed by the commenter is usually customized to 
accommodate data needs that extend far beyond the scope of this rule. 
For example, such systems are typically tailored to an individual 
facility and used to simultaneously manage, among other things, 
criteria pollutants under the CAA, water discharge and permit data 
under the Clean Water Act, employee accident and injury reporting under 
Occupational Safety and Health Administration requirements, and onsite 
hazardous and non-hazardous solid waste information for the Resource 
Conservation and Recovery Act. In contrast, even the largest of 
reporters under this final action will be able to use standard 
spreadsheets or databases to collect the emissions data and perform 
calculations at a facility level. Spreadsheet software can store and 
manipulate tens of thousands of data points, and database software can 
store hundreds of thousands of data points. In short, spreadsheet and 
database software systems are capable of managing far more data than 
will be necessary for even the largest onshore production reporter 
under subpart W. Accordingly, EPA accounted for data management costs 
by factoring in estimates of labor to set up spreadsheets and other 
archiving and recordkeeping activities, as well as equipment costs like 
file cabinets and external hard drives; see the EIA for a complete 
discussion.
    Another assumption contributing to the commenters' high cost 
estimates concerned the extent of sampling required. For example, 
commenters assumed that reporters would need to sample produced natural 
gas. EPA disagrees in part because it expects reporters to already have 
this information and would therefore not need to sample. In particular, 
producers conduct composition analysis of produced natural gas in order 
to pay royalties and taxes; they could use these data to estimate the 
percentage of GHGs instead of analyzing additional samples.
    The commenters also assumed that sampling would be required for 
tanks and dehydrators, which resulted in cost estimates significantly 
higher than EPA's. Although not explicitly stated in the proposed 
subpart W, EPA did not intend for reporters to sample either the low 
pressure separator oil associated with tanks or natural gas going to 
dehydrators. Therefore, EPA has clarified the final rule to allow 
reporters that use the engineering modeling software to rely on the 
software's default values.
    In addition, commenters also assumed that produced water and 
hydrocarbon liquids produced from all reporting wells in the country 
would have to be sampled to determine and report CO<INF>2</INF> 
content; this assumption resulted in a large sampling cost. However, 
EPA never intended for reporters to sample produced water and 
hydrocarbon liquids from all wells but instead targeted EOR operations. 
Therefore, EPA clarified in this final action that the sampling 
requirement for hydrocarbon liquids applies only to EOR operations; EPA 
also clarified in the final rule that

[[Page 74480]]

reporting from produced water emissions sources is not required.
    Finally, in response to comments about the costs to count all 
components to determine equipment leaks, EPA has revised the rule to 
require reporters to count only major equipment (see Section II.E of 
this preamble). EPA expects this revision to reduce the reporters' 
burden because in many cases they already have an inventory of the 
major equipment at each well site.
    For the detailed responses to all of the comments received about 
the costs for onshore production, see Mandatory Greenhouse Gas 
Reporting Rule: EPA's Response to Public Comments, Subpart W: Petroleum 
and Natural Gas Systems (EPA-HQ-OAR-2009-0923).
4. Natural Gas Processing
    Comment: Commenters stated that EPA's estimated compliance costs 
for the natural gas processing segment were too low. They recommended 
that EPA reassess the costs for the processing segment and simplify the 
reporting requirements. In particular, one commenter estimated 
compliance costs at $4.5 billion for the processing segment. Of the 
$4.5 billion, the commenter attributed $3.9 billion to monitoring 
activities at gathering lines and boosting stations. The commenter 
attributed the remainder of its estimate to processing facilities.
    Response: Based on its thorough review of the comments, EPA 
determined that the commenter's estimates for processing facilities 
were higher in part because it made assumptions that were inconsistent 
with EPA's intent. Specifically, it assumed higher-cost, optional 
monitoring methods for processing facilities in its analysis. However, 
EPA agrees with the commenter that the agency's analysis partly 
underestimated the costs at processing facilities to place meters on 
acid gas removal units. Likewise, EPA agrees that the agency's analysis 
did not accurately account for the compliance costs for gathering lines 
and boosting stations in the processing segment.
    In the case of processing facilities, the commenter assumed that 
the rule would require reporters to install permanent flow meters, at 
an assumed cost of $100,000 per meter, to measure emissions from 
compressor venting. However, the rule does not require this and allows 
installation of a port for using a temporary insertion flow meter for 
an annual one-time estimate of vented emissions. Temporary flow meters 
are a significantly cheaper option than permanent meters. Based on 
current market data, EPA estimated approximately $1,000 for each 
installation of a temporary meter port for reciprocating compressors; 
about $5,000 for centrifugal compressors; and about $800 in capital 
costs for a reporter's hotwire anemometer.\10\ Reporters will only need 
to purchase one hotwire anemometer per facility; the hotwire anemometer 
can be used to measure the flow rate at multiple compressors at the 
facility.
---------------------------------------------------------------------------

    \10\ For example, see Global Water Instrumentation Inc., at 
http://www.globalw.com/products/407119.html.
---------------------------------------------------------------------------

    In addition, EPA considered and responded to the commenter's 
assumption about the burden to install permanent outflow meters at acid 
gas removal (AGR) vents. EPA incorrectly assumed that outlet meters 
were already installed at most sites. Specifically, EPA determined upon 
further analysis that the flow rates at the inlet and outlet streams 
for an acid gas removal unit are roughly similar. EPA therefore 
adjusted the calculation method in the final rule to allow the use of 
flow rate at the inlet or outlet, where available, based on its 
assumption that the outlet flow is the same as the inlet flow. In 
addition, if equipment to measure the flow rate, such as CEMS or a 
meter on the vent stack of the acid gas removal unit, is not available, 
the final rule allows reporters to use engineering estimates of flow 
rate of natural gas into the AGR. These revised requirements are 
reflected in the cost analysis in the final EIA.
    Finally, EPA used data about the number of gathering lines and 
boosting stations presented by the commenter as a basis to modify the 
rule requirements. EPA agrees that its EIA for the proposed rule did 
not accurately reflect the number of gathering lines and boosting 
stations that would have been subject to the rule. EPA has dropped the 
requirement for reporting on gathering lines and boosting stations from 
the final rule, so these costs are not included in the analysis. 
Instead, EPA will continue to evaluate options for obtaining emissions 
data from gathering lines and boosting stations in a way that maximizes 
data quality while balancing industry burden; see Section II.F.1 of 
this preamble for further discussion.
5. Natural Gas Distribution
    Comment: Commenters stated that EPA's estimated compliance costs 
for the natural gas distribution segment were too low by orders of 
magnitude. For example, one commenter estimated approximately $11.3 
billion for all reporters in the natural gas distribution segment to 
comply with the rule. A large fraction of this estimate was based on 
the commenter's assumption that the leak detection requirements applied 
to customer meters, i.e., industrial, commercial, and residential 
meters. The commenter did not, however, provide adequate information 
about the basis for the remainder of its cost estimate. In particular, 
the commenter stated that in addition to the costs of using an optical 
gas imaging instrument, each LDC would spend on average about $41 
million annually to comply with the rule, but did not specify any 
compliance activities that accounted for the $41 million.
    Response: EPA has carefully reviewed these comments and disagrees 
that the agency's cost estimates should be orders of magnitude higher. 
EPA has determined that commenters' interpretations of the proposed 
rule were inconsistent with the Agency's intent and this likely 
accounted for the discrepancies between the estimates.
    EPA disagrees with the commenter's cost estimate because it is 
based on the assumption that customer meters are subject to leak 
detection requirements. The commenter assumed that the proposed rule 
required leak detection and emissions estimates for all customer 
meters, i.e., industrial, commercial, and residential meters; the 
commenter estimated reporters would spend approximately $5.4 billion to 
monitor these meters. EPA never intended to require reporting for 
customer meters, which would involve a major cost and have minimal 
effect on the quality of emissions estimates. EPA has therefore 
clarified the final rule to note that sources subject to reporting in 
the natural gas distribution segment do not include customer meters for 
natural gas.
    In addition, EPA has responded to the commenter's recommendation to 
reduce the compliance costs by simplifying the requirements for optical 
gas imaging instrument equipment, e.g., allowing alternatives to 
infrared cameras in some situations. As discussed previously in Section 
II.E of this preamble, this final action provides more flexibility and 
further reduces the compliance cost by allowing facilities to use 
alternative leak detection equipment.
    The commenter did not identify the monitoring activities and 
assumptions underlying its estimate of $5.9 billion to comply with leak 
detection requirements. The commenter noted that it obtained the 
estimate from an informal survey of its members but did not provide 
sufficient information or documentation substantiating what was 
included in this estimate. Because EPA has accounted for the two 
primary issues raised by the commenter (monitoring of customer meters 
and allowable leak detection equipment),

[[Page 74481]]

EPA did not change its cost estimate to reflect the much higher costs 
estimated by the commenter.

C. What are the economic impacts of the rule?

1. Summary of Economic Impacts
    EPA prepared an economic impact analysis to evaluate the impacts of 
the rule on affected small and large reporting entities.
    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.\11\ The national costs of 
the rule are notable because there are a large number of affected 
entities, but per-entity costs are low. 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.
---------------------------------------------------------------------------

    \11\ Note: Before totaling the industry compliance costs, EPA 
estimated costs for each of the industry segments. EPA then summed 
the costs for each segment at the NAICS level for this screening 
assessment.
---------------------------------------------------------------------------

    These low average cost-to-sales ratios indicate that the final rule 
is unlikely to result in significant changes in firms' production 
decisions or other behavioral changes that would result in significant 
changes in prices or quantities in affected markets. Given that prices 
and quantities are unlikely to change significantly, and consistent 
with the agency's guidelines for economic analyses, EPA 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.\12\ Table 8 of this preamble summarizes cost-to-sales 
ratios for affected industries.
---------------------------------------------------------------------------

    \12\ Guidelines for Preparing Economic Analyses (EPA, 2002, p. 
124-125).

                          Table 8--Estimated Cost-to-sales Ratios for Affected Entities
                                                    (Year 1)
----------------------------------------------------------------------------------------------------------------
                                                                                                 Average entity
                                                                                Average cost      cost-to-sales
            NAICS                NAICS Description     MRR Segments included     per entity         ratio \a\
                                                                               ($1,000/entity)      (percent)
----------------------------------------------------------------------------------------------------------------
211.........................  Crude Petroleum and     Onshore Production,                $17.1              0.08
                               Natural Gas             Offshore Production,
                               Extraction.             Processing.
486210......................  Pipeline                Transmission,                       15.7              0.08
                               Transportation of       Underground Storage,
                               Natural Gas.            LNG Storage, and LNG
                                                       Import Terminals.
221210......................  Natural Gas             Distribution..........              13.9              0.06
                               Distribution.
----------------------------------------------------------------------------------------------------------------
\a\ This ratio reflects first year costs. Subsequent year costs will be lower because they do not include
  initial start-up activities.

2. Summary of Comments and Responses
    While EPA received a substantial number of comments on the 
estimated costs for reporters to comply with the rule, there were 
minimal additional comments on the economic impacts, such as changes in 
production or effects on small entities in particular. As discussed in 
the previous section of this preamble, commenters said that EPA 
underestimated the compliance costs and recommended that EPA carefully 
review the economic impact analysis. See the previous section of this 
preamble for a summary; the response to comments document, Mandatory 
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, 
Subpart W: Petroleum and Natural Gas Systems, provides detailed 
comments.
    As discussed in Section III.B.2 of this preamble, EPA collected and 
evaluated cost data from multiple sources, thoroughly reviewed the 
input received through public comments, and weighed the analysis 
prepared for the proposal against this input. EPA has determined that 
this analysis provides a reasonable characterization of costs and 
economic impacts and that the documentation provides adequate 
explanation of how the costs and impacts were estimated.

D. What are the impacts of the 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 85 percent of U.S. GHG emissions from the industry 
segments reported by approximately 2,786 reporters, while keeping 
reporting burden to a minimum. Furthermore, many industry stakeholders 
that EPA met with expressed support for a 25,000 metric ton 
CO<INF>2</INF>e threshold because it sufficiently captures the majority 
of GHG emissions in the United States, while excluding many of the 
smaller facilities and sources. In response to the comments EPA 
received about the monitoring and reporting requirements in specific 
source categories, EPA incorporated changes that reduce burden on 
reporters while maintaining a high level of emissions coverage. 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 industry 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.\13\ 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 9 of this preamble.
---------------------------------------------------------------------------

    \13\ EPA's RFA guidance for rule writers suggests the ``sales'' 
test continues to be the preferred quantitative metric for economic 
impact screening analysis.

[[Page 74482]]



                    Table 9--Estimated Cost-to-Sales Ratios, Sales Receipts ($Million), and Number of Establishments for First Year Costs by Industry and Enterprise Size\a\
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                              SBA Size standard                                                           Owned by enterprises with:
                                                                  in num of       Average cost               -----------------------------------------------------------------------------------
            Industry              NAICS   NAICS Description       employees        per entity        All                                                                               1,000 to
                                                              (effective March      ($1,000/     enterprises    1 to 20    20 to 99   100 to 499     <500     500 to 749  750 to 999     1,499
                                                                  11, 2008)          entity)                   Employees   Employees   Employees   Employees   Employees   Employees   Employees
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Onshore petroleum and natural        211  Crude Petroleum                  500            $17.1        0.08%       1.32%       0.11%       0.05%       0.47%       0.47%       0.03%       0.02%
 gas production; offshore                  and Natural Gas                                       \d\$160,879      $7,573      $6,790      $9,609     $23,972      $4,609      $3,991      $2,805
 petroleum and natural gas                 Extraction.                                              \e\7,629       5,836         456         292       6,584          60          64          31
 production; LNG storage; LNG
 import and export.
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Onshore natural gas processing;   486210  Pipeline                       \(b)\            $15.7        0.08%       0.12%       0.40%       0.24%       0.10%       \(c)\       \(c)\       \(c)\
 onshore natural gas                       Transportation                                         \d\$35,897      $1,035     \c\$106     \c\$394      $2,566       \(c)\       \(c)\       \(c)\
 transmission; underground                 of Natural Gas.                                          \e\1,936          81          27          61          36         169           2          20
 natural gas storage.
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Natural gas distribution.......   221210  Natural Gas                      500            $13.9        0.06%       0.27%       0.03%       0.06%       0.11%       0.07%       0.02%       0.03%
                                           Distribution.                                          \d\$67,275      $2,524      $4,642      $2,878     $13,127        $865      $2,116      $3,757
                                                                                                    \e\2,897         483          86         131         700          68          33          73
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ 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, EPA assumes in this analysis that the enterprise definition above is
  consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses.
\b\ The SBA size standard for NAICS 486210 is $7 million in average annual receipts.
\c\ The U.S. Census Bureau has missing data for this employee range; some estimates were possible using partial data. The receipts for these categories underestimate true value.
\d\ This row presents total annual sales receipts ($Million)for establishments in each enterprise category. Source: U.S. Census Bureau.
\e\ This row presents total number of establishments in each enterprise category. Source: U.S. Census Bureau.


[[Page 74483]]

    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. The only exception is the ratio 
for enterprises with 1-20 employees for crude petroleum and natural gas 
extraction, which is greater than 1 percent but less than 2 percent. It 
is important to note that this analysis does not screen out entities 
that would be below the reporting threshold. Based on further analysis 
of production data in HPDI, EPA estimates that in most cases, the 
smaller enterprises have very small operations (such as a single family 
owning a few production wells) that are unlikely to cross the 25,000 
metric tons CO<INF>2</INF>e reporting threshold.
    In other cases, a small enterprise (less than 20 employees) may own 
large operations but conduct nearly all of its operations through 
service providers, so that it has few employees of its own. Such 
enterprises, however, tend to have higher annual revenues than those 
with small operations and therefore have lower cost-to-sales ratios. 
The review of production data by operator in HPDI shows a ratio of less 
than one percent for the operators expected to meet the reporting 
threshold.
    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. That is, the analysis assumes that each 
establishment is a unique enterprise. To the extent that a single 
parent may own multiple establishments, the small entity impacts could 
be lower.
    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 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 
established a reasonable balance of direct measurement, engineering 
estimation, and emission factors based monitoring methods to quantify 
emissions, which provides flexibility to entities and helps minimize 
reporting costs.
2. Summary of Comments and Responses
    Comment: Some commenters noted concerns about the rule's impact on 
small businesses, in particular that small businesses would have to 
apply the monitoring methods specified in the rule to determine whether 
they have to report under the rule. One commenter recommended that EPA 
redo its analysis of the rule's impacts on small businesses using 
``more accurate economic impact data,'' but did not include or identify 
alternative data sources for such an analysis. See the response to 
comments document, Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart W: Petroleum and Natural Gas 
Systems, for the detailed comments.
    Response: EPA has assessed the economic impact of the final rule on 
small entities and concluded that this action will not have a 
significant economic impact on a substantial number of small entities. 
While the commenter did not provide details in its recommendation that 
EPA redo the small business analysis using ``more accurate economic 
impact data,'' EPA acknowledges the importance of using the best 
available economic data. Accordingly, EPA analyzed the economic impact 
on small entities using the revised cost estimates discussed in this 
section of the preamble and in the EIA. These cost estimates were the 
same order of magnitude as those estimated under the proposal; the 
estimates also reflected improvements made in response to comments as 
well as changes to the monitoring requirements in the final rule.
    In addition, EPA's assessment of the economic impacts on small 
entities continued to rely on data from the Statistics of U.S. 
Businesses, a well-known database that provides national information on 
the distribution of economic variables by the size of entity. As noted 
in the EIA, these data were developed in cooperation with, and 
partially funded by, the Office of Advocacy of the Small Business 
Administration. Complete documentation of this analysis can be found in 
Section 5.2 of the EIA for the final rule.
    Finally, in response to concerns about the cost to make a reporting 
determination, EPA intends to provide screening tools. As discussed 
above, these tools will aid small businesses and other potential 
reporters in determining whether or not they have to report.
    The response to comments document, Mandatory Greenhouse Gas 
Reporting Rule: EPA's Response to Public Comments, Subpart W: Petroleum 
and Natural Gas Systems, presents the detailed comments and responses 
related to the rule's impact on small businesses.

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

    EPA examined the potential benefits of the final subpart W. The 
benefits of a reporting system are based on their relevance to policy 
making, transparency, 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 policymakers and the public by increased availability of 
facility emissions data. Public data on emissions allows for 
accountability of emitters to the public. Citizens, community groups, 
and labor unions have made use of data from Pollutant Release and 
Transfer Registers to negotiate directly with emitters 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. Facility-
specific emissions data will also aid local, State, and national 
policymakers as they evaluate and consider future climate change policy 
decisions.
    The benefits of mandatory reporting of petroleum and natural gas 
systems GHG emissions to government also include enhancing existing 
programs, such as the Natural Gas STAR Program, and that provide 
significant benefits. Through the Natural Gas STAR Program, EPA has 
identified over 120 proven, cost effective technologies and practices 
to reduce emissions of methane--the primary constituent of natural 
gas--from operations in all of the major industry sectors--production, 
gathering and processing, transmission, and distribution. The final 
subpart W will increase knowledge of the location and magnitude of 
significant methane emissions sources in the petroleum and natural gas 
industry, which can result in improvements in these technologies and 
the identification of new emissions reducing technologies.

[[Page 74484]]

    Benefits to industry of GHG emissions monitoring include the value 
of having 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.
    The EIA for this final rule as well as the RIA for 40 CFR part 98 
summarize the anticipated benefits, 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 justify the estimated costs.

IV. Statutory and Executive Order Review

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 final rule have 
been submitted for approval to the Office of Management and Budget 
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The 
Information Collection Request (ICR) document prepared by EPA has been 
assigned EPA ICR number 2376.02.
    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 
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 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.
    The projected cost and hour burden for non-Federal respondents is 
$27.7 million and 396,474 hours per year. The estimated average burden 
per response is 90.71 hours; the frequency of response is annual for 
all respondents that must comply with the final rule's reporting 
requirements; and the estimated average number of likely respondents 
per year is 2,786. 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 $0.74 million), a 
total operation and maintenance component (averaging $1.7 million per 
year), and a labor cost component (averaging $25.3 million per 
year).\14\
---------------------------------------------------------------------------

    \14\ 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.
---------------------------------------------------------------------------

    Burden is defined at 5 CFR 1320.3(b). These cost numbers differ 
from those shown elsewhere in the EIA for these subparts because the 
information collection request (ICR) costs represent the average cost 
over the first three years of the rule, but costs are reported 
elsewhere in the EIA for the subparts for the first year of the rule 
and for subsequent years of the rule. In addition, the ICR focuses on 
respondent burden, while the EIA includes both national compliance 
costs and the burden for EPA to implement the rule.
    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. When this ICR is 
approved by OMB, the Agency will publish a technical amendment to 40 
CFR part 9 in the Federal Register to display the OMB control number 
for the approved information collection requirements contained in this 
final rule.

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 final rule on small 
entities, small entity is defined as: (1) A small business as defined 
by the Small Business Administration's regulations at 13 CFR 121.201; 
(2) a small governmental jurisdiction that is a government of a city, 
county, town, school district or special district with a population of 
less than 50,000; and (3) a small organization that is any not-for-
profit enterprise that is independently owned and operated and is not 
dominant in its field.
    After considering the economic impacts of this final action on 
small entities, I certify that this action will not have a significant 
economic impact on a substantial number of small entities.
    The small entities directly regulated by this final rule include 
small businesses in the petroleum and gas industry, small governmental 
jurisdictions and small non-profits. EPA has determined that some small 
businesses will be affected because their production processes emit 
GHGs exceeding the reporting threshold.
    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

[[Page 74485]]

businesses. This ratio constitutes a ``sales'' test that computes the 
annualized compliance costs of this final 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 9 of this preamble, 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. It is important to note that this analysis does not screen out 
entities that would be below the reporting threshold. Although the 
costs to receipts for entities in onshore production with 1-20 
employees is slightly over 1 percent, most of these facilities would 
likely not exceed the 25,000 mtCO<INF>2</INF>e threshold, a threshold 
supported by many stakeholders as one that sufficiently captures the 
majority of GHG emissions while excluding small facilities.
    EPA also concluded that the final rulemaking would not affect a 
small organization that is any not-for-profit enterprise that is 
independently owned and operated and is not dominant in its field. 
Specifically, the data listing entities in each segment of the 
petroleum and natural gas industry did not include any non-profit 
entities.
    In addition, EPA determined that the final rulemaking would not 
have a significant impact on small governmental jurisdictions. EPA 
determined that one segment of the petroleum and natural gas industry 
might include small governments affected by the final rulemaking. A 
comparison of the compliance costs to the revenue of potentially 
affected small governmental jurisdictions revealed that the costs of 
the rule are less than 1 percent of revenues.
    Although this final 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 final rule on small 
entities. For example, EPA determined appropriate thresholds that 
reduce the number of small businesses reporting. In addition, EPA 
allows different monitoring methods for different emissions sources, 
requiring direct measurement only for selected sources. Also, EPA 
intends to provide a screening tool that will help small businesses 
make a reporting determination (see Section II.F.6 of this preamble). 
Finally, EPA is establishing 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 website, along with a general fact sheet for the 
rule, information sheets for every source category, and an FAQ 
document. EPA also operated a hotline to answer questions about the 
final rule. EPA 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 final 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 final rule.
    EPA has therefore concluded that this final action will not have a 
significant economic impact on a substantial number of small entities.

D. Unfunded Mandates Reform Act (UMRA)

    This 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 sector in any one year. 
EPA estimated the cost to individual facilities that may have to report 
to this final rule using actual facility characteristics such as 
throughput and size. EPA also determined the costs to non-reporters for 
determination to report. The sum of these costs for the entire industry 
has been estimated to be less than $100 million. Thus, this rule is not 
subject to the requirements of sections 202 or 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. Based on EPA's 
analysis of the rule's impact on small entities, the Agency determined 
that natural gas distribution is the only industry segment that would 
potentially have small governments affected by the rule. In this 
segment, however, the facilities owned or operated by small governments 
are expected to be too small to trigger the 25,000 metric tons 
CO<INF>2</INF>e reporting threshold.

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 EO 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, EO 13132 does not apply to 
this action.

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. EPA conducted an analysis 
to determine potential impact of this action on tribes that own or 
operate petroleum and natural gas systems (EPA-HQ-OAR-2009-0923-XXX). 
First, EPA analyzed a comprehensive listing of all operators of 
petroleum and natural gas systems in the United States in conducting 
the threshold analysis. In a separate analysis, EPA researched 
additional available data to determine which tribal entities may own or 
operate petroleum and natural gas systems that could be impacted by 
this final action. As a result of those analyses, EPA found one tribe 
that may potentially be impacted by this final action. Finally, during 
the comment period for the April 2010 proposal, EPA received comment 
from one tribe, Southern Ute, which were specific to the proposed 
reporting methodologies.
    As further discussed in the 2009 final rule that established the 
Greenhouse Gas reporting program, EPA believes that there are minimal 
impacts to tribes. Tribes could be required to submit an annual GHG 
report for any facility they own or operate that is subject to the 
rule. Specifically, tribes that own or operate oil and gas operations 
could be required to report emissions under this

[[Page 74486]]

rulemaking. It should be noted that the owner or operator of any 
privately owned sources located on a reservation would be required to 
report for any applicable facility. EPA sought opportunities to provide 
information to tribal governments and representatives during rule 
development. As stated in IV.F of this preamble, Executive Order 13175: 
Consultation and Coordination with Indian Tribal Governments of 40 CFR 
part 98, and in consultation with EPA's American Indian Environment 
Office, EPA's outreach plan for the Greenhouse Gas Reporting Rule 
included tribes. EPA conducted several conference calls with Tribal 
organizations during the proposal phase of part 98. 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 The Climate Registry (TCR).
    In addition, EPA prepared a short article on the Greenhouse Gas 
Reporting Program 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 Greenhouse Gas Reporting Program, at the 
National Tribal Conference on Environmental Management on June 24-26, 
2008. In addition, EPA distributed copies of a short information sheet 
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 participated in a conference call with Tribal air coordinators in 
April 2009 and prepared a guidance sheet for Tribal governments on the 
final Part 98. It was posted on the Greenhouse Gas Reporting Program 
Web site and published in the Tribal Air Newsletter.
    As required by section 7(a), EPA's Tribal Consultation Official has 
certified that the requirements of the Executive Order have been met in 
a meaningful and timely manner. A copy of the certification is included 
in the docket for this action.

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

    This action is not subject to EO 13045 because it does not 
establish an environmental standard intended to mitigate health or 
safety risks. Also, this is not an economically significant rule under 
EO 12866, and thus EO 13045 does not apply.

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

    This final 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, EPA has concluded that this final rule is not 
likely to have any adverse energy effects. This final rule relates to 
monitoring, reporting and recordkeeping at petroleum and gas facilities 
that emit over 25,000 mtCO<INF>2</INF>e and does not impact energy 
supply, distribution or use. Therefore, EPA concludes that this final 
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 final rule. 
Instead, EPA reviewed existing rules for source categories and 
voluntary greenhouse gas programs and 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 final 
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 12898 (59 FR 7629, February 16, 1994) establishes 
Federal executive policy on environmental justice. Its main provision 
directs Federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the United States.
    EPA has determined that this final 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.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), 
generally provides that before a rule may take effect, the agency 
promulgating the rule must submit a rule report, which includes a copy 
of the rule, to each House of the Congress and to the Comptroller 
General of the United States. EPA will submit a report containing this 
rule and other required information to the U.S. Senate, the U.S. House 
of Representatives, and the Comptroller General of the U.S. prior to 
publication of the rule in the Federal Register. A major rule cannot 
take effect until 60 days after it is published in the Federal 
Register. This action is not a ``major rule'' as defined by 5 U.S.C. 
804(2). This rule will be effective December 30, 2010.

List of Subjects in 40 CFR Part 98

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


[[Page 74487]]


    Dated: November 8, 2010.
Lisa P. Jackson,
Administrator.

0
For the reasons stated in the preamble, title 40, chapter I, of the 
Code of Federal Regulations is amended as follows:

PART 98--[AMENDED]

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

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

Subpart A--[Amended]

0
2. Section 98.2 is amended by revising the introductory text to 
paragraph (a) 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:
* * * * *

0
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.
* * * * *
    Air injected flare means a flare in which air is blown into the 
base of a flare stack to induce complete combustion of gas.
* * * * *
    Blowdown vent stack emissions mean natural gas and/or 
CO<INF>2</INF> released due to maintenance and/or blowdown operations 
including 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 an 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 or CO<INF>2</INF> 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 or 
CO<INF>2</INF> from escaping to the atmosphere.
    Centrifugal compressor dry seal emissions mean natural gas or 
CO<INF>2</INF> 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 vent emissions means 
emissions that occur when the high-pressure oil barriers for 
centrifugal compressors are depressurized to release absorbed natural 
gas or CO<INF>2.</INF> 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.
* * * * *
    Continuous bleed means a continuous flow of pneumatic supply gas to 
the process measurement device (e.g. level control, temperature 
control, pressure control) where the supply gas pressure is modulated 
by the process condition, and then flows to the valve controller where 
the signal is compared with the process set-point to adjust gas 
pressure in the valve actuator.
* * * * *
    Dehydrator means a device in which a liquid absorbent (including 
desiccant, ethylene glycol, diethylene glycol, or triethylene glycol) 
directly contacts a natural gas stream to absorb water vapor.
    Dehydrator vent emissions means natural gas and CO<INF>2</INF> 
released from a natural gas dehydrator system absorbent (typically 
glycol) reboiler or regenerator to the atmosphere or a flare, 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 or absorption. Desiccants 
include activated alumina, pelletized calcium chloride, lithium 
chloride and granular silica gel material. Wet natural gas is passed 
through a bed of the granular or pelletized solid adsorbent or 
absorbent in these dehydrators. As the wet gas contacts the surface of 
the particles of desiccant material, water is adsorbed on the surface 
or absorbed and dissolves the surface of these desiccant particles. 
Passing through the entire desiccant bed, almost all of the water is 
adsorbed onto or absorbed into the desiccant material, leaving the dry 
gas to exit the contactor.
* * * * *
    Gas conditions mean the actual temperature, volume, and pressure of 
a gas sample.
* * * * *
    Gas to oil ratio (GOR) means the ratio of the volume of gas at 
standard temperature and pressure that is produced from a volume of oil 
when depressurized to standard temperature and pressure.
* * * * *
    High-bleed pneumatic devices are automated, continuous bleed 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 that is 
regulated by the process condition flows to a valve actuator controller 
where it vents continuously (bleeds) to the atmosphere at a rate in 
excess of 6 standard cubic feet per hour.
* * * * *
    Intermittent 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. These are snap-acting or throttling devices that discharge 
the full volume of the actuator intermittently when control action is 
necessary, but does not bleed continuously.
* * * * *
    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 that is regulated by the 
process condition flows to a valve actuator controller where it vents 
continuously (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

[[Page 74488]]

natural gas to move a piston or diaphragm, which pumps liquids on the 
opposite side of the piston or diaphragm.
* * * * *
    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. 1331, and of which the subsoil and seabed appertain to the 
United States and are subject to its jurisdiction and control.
* * * * *
    Reciprocating compressor means a piece of equipment that increases 
the pressure of a process natural gas or CO<INF>2</INF> 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 or CO<INF>2</INF> 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.
* * * * *
    Sales oil means produced crude oil or condensate measured at the 
production lease automatic custody transfer (LACT) meter or custody 
transfer tank gauge.
* * * * *
    Sour natural gas means natural gas that contains significant 
concentrations of hydrogen sulfide (H<INF>2</INF>S)and/or carbon 
dioxide (CO<INF>2</INF>) 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 (H<INF>2</INF>S) and/or carbon dioxide (CO<INF>2</INF>) that 
does not require (or has already had) acid gas treatment to meet 
pipeline corrosion-prevention specifications for transmission and 
distribution.
* * * * *
    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.
* * * * *
    Well completions means the process that allows for the flow of 
petroleum or natural gas from newly drilled wells to expel drilling and 
reservoir fluids and test the reservoir flow characteristics, steps 
which may vent produced gas to the atmosphere via an open pit or tank. 
Well completion also involves connecting the well bore to the 
reservoir, which may include treating the formation or installing 
tubing, packer(s), or lifting equipment, steps that do not 
significantly vent natural gas to the atmosphere. This process may also 
include high-rate flowback of injected gas, water, oil, and proppant 
used to fracture or re-fracture and prop open new fractures in existing 
lower permeability gas reservoirs, steps that may vent large quantities 
of produced gas to the atmosphere.
    Well workover means the process(es) of performing one or more of a 
variety of remedial operations on producing petroleum and natural gas 
wells to try to increase production. This process also includes high-
rate flowback of injected gas, water, oil, and proppant used to re-
fracture and prop-open new fractures in existing low permeability gas 
reservoirs, steps that may vent large quantities of produced gas to the 
atmosphere.
    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. Wellhead equipment includes all equipment, permanent and 
portable, located on the improved land area (i.e. well pad) surrounding 
one or multiple wellheads.
    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.''
* * * * *

0
4. Section 98.7 is amended by adding and reserving paragraphs (n) and 
(o), and by adding paragraphs (p) and (q) to read as follows:


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

* * * * *
    (n) [Reserved]
    (o) [Reserved]
    (p) The following material is available for purchase from the 
American Association of Petroleum Geologists, 1444 South Boulder 
Avenue, Tulsa, Oklahoma 74119, (918) 584-2555, http://www.aapg.org.
    (1) Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG 
Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J. 
Wagner, Jr., Volume 75, Number 10 (October 1991), pages 1644-1651, IBR 
approved for Sec.  98.238.
    (2) Alaska Geological Province Boundary Map, Compiled by the 
American Association of Petroleum Geologists Committee on Statistics of 
Drilling in cooperation with the USGS, 1978, IBR approved for Sec.  
98.238.
    (q) The following material is available from the Energy Information 
Administration (EIA), 1000 Independence Ave., SW., Washington, DC 
20585, (202) 586-8800, http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/field_code_master_list/current/pdf/fcml_all.pdf.
    (1) Oil and Gas Field Code Master List 2008, DOE/EIA0370(08), 
January 2009, IBR approved for Sec.  98.238.
    (2) [Reserved]

0
5. Table A-4 to subpart A is amended by adding an entry for ``Petroleum 
and Natural Gas Systems (subpart W)'' at the end of the table to read 
as follows:

   Table A-4 to Subpart A--Source Category List for Sec.   98.2(a)(2)
------------------------------------------------------------------------
 
-------------------------------------------------------------------------
Source Categories \a\ Applicable in 2010 and Future Years
 
                              * * * * * * *
Additional Source Categories \a\ Applicable in 2011 and Future Years
 
                              * * * * * * *
    Petroleum and Natural Gas Systems (subpart W)
------------------------------------------------------------------------
\a\ Source categories are defined in each applicable subpart.
 

0
6. Add Subpart W--Petroleum and Natural Gas Systems to read as follows:

Subpart W--Petroleum and Natural Gas Systems

Sec.
98.230 Definition of the source category.

[[Page 74489]]

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.
Table W-1A to Subpart W of Part 98--Default Whole Gas Emission 
Factors for Onshore Petroleum and Natural Gas Production
Table W-1B to Subpart W of Part 98--Default Average Component Counts 
for Major Onshore Natural Gas Production Equipment
Table W-1C to Subpart W of Part 98--Default Average Component Counts 
For Major Crude Oil Production Equipment
Table W-1D of Subpart W of Part 98--Designation Of Eastern And 
Western U.S.
Table W-2 to Subpart W of Part 98--Default Total Hydrocarbon 
Emission Factors for Onshore Natural Gas Processing
Table W-3 to Subpart W of Part 98--Default Total Hydrocarbon 
Emission Factors for Onshore Natural Gas Transmission Compression
Table W-4 to Subpart W of Part 98--Default Total Hydrocarbon 
Emission Factors for Underground Natural Gas Storage
Table W-5 to Subpart W of Part 98--Default Methane Emission Factors 
for Liquefied Natural Gas (LNG) Storage
Table W-6 to Subpart W of Part 98--Default Methane Emission Factors 
for LNG Import and Export Equipment
Table W-7 to Subpart W of Part 98--Default Methane Emission Factors 
for Natural Gas Distribution


Sec.  98.230  Definition of the source category.

    (a) This source category consists of the following industry 
segments:
    (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 
processes and/or transfers such hydrocarbons to storage, transport 
vessels, or onshore. In addition, offshore production includes 
secondary platform structures connected to the platform structure via 
walkways, storage tanks associated with the platform structure and 
floating production and storage offloading equipment (FPSO). This 
source category does not include reporting of emissions from offshore 
drilling and exploration that is not conducted on production platforms.
    (2) Onshore petroleum and natural gas production. Onshore petroleum 
and natural gas production means all equipment on a well pad or 
associated with a well pad (including compressors, generators, or 
storage facilities), and portable non-self-propelled equipment on a 
well pad or associated with a well pad (including well drilling and 
completion equipment, workover equipment, gravity separation equipment, 
auxiliary non-transportation-related equipment, and leased, rented or 
contracted equipment) used in the production, extraction, recovery, 
lifting, stabilization, separation or treating of petroleum and/or 
natural gas (including condensate). This equipment also includes 
associated storage or measurement vessels and all enhanced oil recovery 
(EOR) operations using CO<INF>2</INF>, 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. Natural gas processing 
separates and recovers natural gas liquids (NGLs) and/or other non-
methane gases and liquids from a stream of produced natural gas using 
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 CO<INF>2</INF> separated from 
natural gas streams. This segment also includes all residue gas 
compression equipment owned or operated by the natural gas processing 
facility, whether inside or outside the processing facility fence. This 
source category does not include reporting of emissions from gathering 
lines and boosting stations. This source category includes:
    (i) All processing facilities that fractionate.
    (ii) All processing facilities that do not fractionate with 
throughput of 25 MMscf per day or greater.
    (4) Onshore natural gas transmission compression. Onshore natural 
gas transmission compression means any stationary combination of 
compressors that move natural gas 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 may include equipment for liquids 
separation, natural gas dehydration, and tanks for the storage of water 
and hydrocarbon liquids. Residue (sales) gas compression operated by 
natural gas processing facilities are included in the onshore natural 
gas processing segment and are excluded from this segment. This source 
category also does not include reporting of emissions from gathering 
lines and boosting stations--these sources are currently not covered by 
subpart W.
    (5) Underground natural gas storage. Underground natural gas 
storage means subsurface storage, including depleted gas or oil 
reservoirs and salt dome caverns that store 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 compression, dehydration and flow measurement, and excluding 
transmission pipelines); and all the wellheads connected to the 
compression units located at the facility that inject and recover 
natural gas into and from the underground reservoirs.
    (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, 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 the 
distribution pipelines (not interstate transmission pipelines or 
intrastate transmission pipelines) and metering and regulating 
equipment at city gate stations, and excluding customer meters, that 
physically deliver natural gas to end users and is operated by a Local 
Distribution Company (LDC) that is regulated as a separate operating 
company by a public utility commission or that is operated as an 
independent municipally-owned distribution system. This segment 
excludes customer meters and infrastructure and pipelines (both 
interstate and intrastate) delivering natural gas directly to major 
industrial users and ``farm taps'' upstream of the local distribution 
company inlet.
    (b) [Reserved]


Sec.  98.231  Reporting threshold.

    (a) You must report GHG emissions under this subpart if your 
facility contains petroleum and natural gas systems and the facility 
meets the requirements of Sec.  98.2(a)(2). Facilities must report 
emissions from the onshore petroleum and natural gas production

[[Page 74490]]

industry segment only if emission sources specified in paragraph Sec.  
98.232(c) emit 25,000 metric tons of CO<INF>2</INF> equivalent or more 
per year. Facilities must report emissions from the natural gas 
distribution industry segment only if emission sources specified in 
paragraph Sec.  98.232(i) emit 25,000 metric tons of CO<INF>2</INF> 
equivalent or more per year.
    (b) For applying the threshold defined in Sec.  98.2(a)(2), natural 
gas processing facilities must also include owned or operated residue 
gas compression equipment.


Sec.  98.232  GHGs to report.

    (a) You must report CO<INF>2</INF>, CH<INF>4</INF>, and 
N<INF>2</INF>O emissions from each industry segment specified in 
paragraph (b) through (i) of this section, CO<INF>2</INF>, 
CH<INF>4</INF>, and N<INF>2</INF>O emissions from each flare as 
specified in paragraph (j) of this section, and stationary and portable 
combustion emissions as applicable as specified in paragraph (k) of 
this section.
    (b) For offshore petroleum and natural gas production, report 
CO<INF>2,</INF> CH<INF>4,</INF> and N<INF>2</INF>O emissions from 
equipment leaks, vented emission, and flare emission source types as 
identified in the data collection and emissions estimation study 
conducted by BOEMRE in compliance with 30 CFR 250.302 through 304. 
Offshore platforms do not need to report portable emissions.
    (c) For an onshore petroleum and natural gas production facility, 
report CO<INF>2,</INF> CH<INF>4</INF>, and N<INF>2</INF>O emissions 
from only the following source types on a well pad or associated with a 
well pad:
    (1) Natural gas pneumatic device venting.
    (2) [Reserved]
    (3) Natural gas driven pneumatic pump venting.
    (4) Well venting for liquids unloading.
    (5) Gas well venting during well completions without hydraulic 
fracturing.
    (6) Gas well venting during well completions with hydraulic 
fracturing.
    (7) Gas well venting during well workovers without hydraulic 
fracturing.
    (8) Gas well venting during well workovers with hydraulic 
fracturing.
    (9) Flare stack emissions.
    (10) Storage tanks vented emissions from produced hydrocarbons.
    (11) Reciprocating compressor rod packing venting.
    (12) Well testing venting and flaring.
    (13) Associated gas venting and flaring from produced hydrocarbons.
    (14) Dehydrator vents.
    (15) [Reserved]
    (16) EOR injection pump blowdown.
    (17) Acid gas removal vents.
    (18) EOR hydrocarbon liquids dissolved CO<INF>2</INF>.
    (19) Centrifugal compressor venting.
    (20) [Reserved]
    (21) Equipment leaks from valves, connectors, open ended lines, 
pressure relief valves, pumps, flanges, and other equipment leak 
sources (such as instruments, loading arms, stuffing boxes, compressor 
seals, dump lever arms, and breather caps).
    (22) You must use the methods in Sec.  98.233(z) and report under 
this subpart the emissions of CO<INF>2</INF>, CH<INF>4</INF>, and 
N<INF>2</INF>O from stationary or portable fuel combustion equipment 
that cannot move on roadways under its own power and drive train, and 
that are located at an onshore production well pad. Stationary or 
portable equipment are the following equipment which are integral to 
the extraction, processing or movement of oil or natural gas: Well 
drilling and completion equipment, workover equipment, natural gas 
dehydrators, natural gas compressors, electrical generators, steam 
boilers, and process heaters.
    (d) For onshore natural gas processing, report CO<INF>2</INF> and 
CH<INF>4</INF> emissions from the following sources:
    (1) Reciprocating compressor rod packing venting.
    (2) Centrifugal compressor venting.
    (3) Blowdown vent stacks.
    (4) Dehydrator vents.
    (5) Acid gas removal vents.
    (6) Flare stack emissions.
    (7) Equipment leaks from valves, connectors, open ended lines, 
pressure relief valves, and meters.
    (e) For onshore natural gas transmission compression, report 
CO<INF>2</INF> and CH<INF>4</INF> emissions from the following sources:
    (1) Reciprocating compressor rod packing venting.
    (2) Centrifugal compressor venting.
    (3) Transmission storage tanks.
    (4) Blowdown vent stacks.
    (5) Natural gas pneumatic device venting.
    (6) [Reserved]
    (7) Equipment leaks from valves, connectors, open ended lines, 
pressure relief valves, and meters.
    (f) For underground natural gas storage, report CO<INF>2</INF> and 
CH<INF>4</INF> emissions from the following sources:
    (1) Reciprocating compressor rod packing venting.
    (2) Centrifugal compressor venting.
    (3) Natural gas pneumatic device venting.
    (4) [Reserved]
    (5) Equipment leaks from valves, connectors, open ended lines, 
pressure relief valves, and meters.
    (g) For LNG storage, report CO<INF>2</INF> and CH<INF>4</INF> 
emissions from the following sources:
    (1) Reciprocating compressor rod packing venting.
    (2) Centrifugal compressor venting.
    (3) Equipment leaks from valves; pump seals; connectors; vapor 
recovery compressors, and other equipment leak sources.
    (h) LNG import and export equipment, report CO<INF>2</INF> and 
CH<INF>4</INF> emissions from the following sources:
    (1) Reciprocating compressor rod packing venting.
    (2) Centrifugal compressor venting.
    (3) Blowdown vent stacks.
    (4) Equipment leaks from valves, pump seals, connectors, vapor 
recovery compressors, and other equipment leak sources.
    (i) For natural gas distribution, report emissions from the 
following sources:
    (1) Above ground meters and regulators at custody transfer city 
gate stations, including equipment leaks from connectors, block valves, 
control valves, pressure relief valves, orifice meters, regulators, and 
open ended lines. Customer meters are excluded.
    (2) Above ground meters and regulators at non-custody transfer city 
gate stations, including station equipment leaks. Customer meters are 
excluded.
    (3) Below ground meters and regulators and vault equipment leaks. 
Customer meters are excluded.
    (4) Pipeline main equipment leaks.
    (5) Service line equipment leaks.
    (6) Report under subpart W of this part the emissions of 
CO<INF>2</INF>, CH<INF>4</INF>, and N<INF>2</INF>O emissions from 
stationary fuel combustion sources following the methods in Sec.  
98.233(z).
    (j) All applicable industry segments must report the 
CO<INF>2</INF>, CH<INF>4</INF>, and N<INF>2</INF>O emissions from each 
flare.
    (k) Report under subpart C of this part (General Stationary Fuel 
Combustion Sources) the emissions of CO<INF>2</INF>, CH<INF>4</INF>, 
and N<INF>2</INF>O from each stationary fuel combustion unit by 
following the requirements of subpart C. Onshore petroleum and natural 
gas production facilities must report stationary and portable 
combustion emissions as specified in paragraph (c) of this section. 
Natural gas distribution facilities must report stationary combustion 
emissions as specified in paragraph (i) of this section.
    (l) You must report under subpart PP of this part (Suppliers of 
Carbon Dioxide), CO<INF>2</INF> emissions captured and transferred off 
site by following the requirements of subpart PP.


Sec.  98.233  Calculating GHG emissions.

    You must calculate and report the annual GHG emissions as 
prescribed in this section. For actual conditions,

[[Page 74491]]

reporters must use average atmospheric conditions or typical operating 
conditions as applicable to the respective monitoring methods in this 
section.
    (a) Natural gas pneumatic device venting. Calculate CH<INF>4</INF> 
and CO<INF>2</INF> emissions from continuous high bleed, continuous low 
bleed, and intermittent bleed natural gas pneumatic devices using 
Equation W-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.173


Where:

Mass<INF>s,i</INF> = Annual total mass GHG emissions in metric tons 
CO<INF>2</INF>e per year at standard conditions from a natural gas 
pneumatic device vent, for GHG i.
Count = Total number of continuous high bleed, continuous low bleed, 
or intermittent bleed natural gas pneumatic devices of each type as 
determined in paragraph (a)(1) of this section.
EF = Population emission factors for natural gas pneumatic device 
venting listed in Tables W-1A, W-3, and W-4 of this subpart for 
onshore petroleum and natural gas production, onshore natural gas 
transmission compression, and underground natural gas storage 
facilities, respectively.
GHG<INF>i</INF> = For onshore petroleum and natural gas production 
facilities, concentration of GHG i, CH<INF>4</INF> or 
CO<INF>2</INF>, in produced natural gas; for facilities listed in 
Sec.  98.230(a)(3) through (a)(8), GHG<INF>i</INF> equals 1.
Conv<INF>i</INF> = Conversion from standard cubic feet to metric 
tons CO<INF>2</INF>e; 0.000410 for CH<INF>4</INF>, and 0.00005357 
for CO<INF>2</INF>.
24 * 365 = Conversion to yearly emissions estimate.

    (1) For onshore petroleum and natural gas production, provide the 
total number of continuous high bleed, continuous low bleed, or 
intermittent bleed natural gas pneumatic devices of each type as 
follows:
    (i) In the first calendar year, for the total number of each type, 
you may count the total of each type, or count any percentage number of 
each type plus an engineering estimate based on best available data of 
the number not counted.
    (ii) In the second consecutive year, for the total number of each 
type, you may count the total of each type, or count any percentage 
number of each type plus an engineering estimate based on best 
available data of the number not counted.
    (iii) In the third consecutive calendar year, complete the count of 
all pneumatic devices, including any changes to equipment counted in 
prior years.
    (iv) For the calendar year immediately following the third 
consecutive calendar year, and for calendar years thereafter, 
facilities must update the total count of pneumatic devices and adjust 
accordingly to reflect any modifications due to changes in equipment.
    (2) For onshore natural gas transmission compression and 
underground natural gas storage, all natural gas pneumatic devices must 
be counted in the first year and updated every calendar year.
    (b) [Reserved]
    (c) Natural gas driven pneumatic pump venting. Calculate 
CH<INF>4</INF> and CO<INF>2</INF> emissions from natural gas driven 
pneumatic pump venting using Equation W-2 of this section. Natural gas 
driven pneumatic pumps covered in paragraph (e) of this section do not 
have to report emissions under paragraph (c) of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.174


Where:

Mass<INF>s,i</INF> = Annual total mass GHG emissions in metric tons 
CO<INF>2</INF>e per year at standard conditions from all natural gas 
pneumatic pump venting, for GHG i.
Count = Total number of natural gas pneumatic pumps.
EF = Population emission factors for natural gas pneumatic pump 
venting listed in Tables W-1A of this subpart for onshore petroleum 
and natural gas production.
GHG<INF>i</INF> = Concentration of GHG i, CH<INF>4</INF> or 
CO<INF>2</INF>, in produced natural gas.
Conv<INF>i</INF> = Conversion from standard cubic feet to metric 
tons CO<INF>2</INF>e; 0.000410 for CH<INF>4</INF>, and 0.00005357 
for CO<INF>2</INF>.
24 * 365 = Conversion to yearly emissions estimate.

    (d) Acid gas removal (AGR) vents. For AGR vent (including processes 
such as amine, membrane, molecular sieve or other absorbents and 
adsorbents), calculate emissions for CO<INF>2</INF> only (not 
CH<INF>4</INF>) vented directly to the atmosphere or through a flare, 
engine (e.g. permeate from a membrane or de-adsorbed gas from a 
pressure swing adsorber used as fuel supplement), or sulfur recovery 
plant using any of the calculation methodologies described in paragraph 
(d) of this section.
    (1) Calculation Methodology 1. If you operate and maintain a CEMS 
that measures CO<INF>2</INF> emissions according to subpart C of this 
part, you must calculate CO<INF>2</INF> emissions under this subpart by 
following the Tier 4 Calculation Methodology and all associated 
requirements for Tier 4 in subpart C of this part (General Stationary 
Fuel Combustion Sources). If CEMS and/or volumetric flow rate monitor 
are not available, you may install a CEMS that complies with the Tier 4 
Calculation Methodology in subpart C of this part (General Stationary 
Fuel Combustion).
    (2) Calculation Methodology 2. If CEMS is not available, use the 
CO<INF>2</INF> composition and annual volume of vent gas to calculate 
emissions using Equation W-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.175

Where:

E<INF>a,CO2</INF> = Annual volumetric CO<INF>2</INF> emissions at 
actual conditions, in cubic feet per year.
V<INF>S</INF> = Total annual volume of vent gas flowing out of the 
AGR unit in cubic feet per year at actual conditions as determined 
by flow meter using methods set forth in Sec.  98.234(b).
Vol<INF>CO2</INF> = Volume fraction of CO<INF>2</INF> content in 
vent gas out of the AGR unit as determined in (d)(6) of this 
section.

    (3) Calculation Methodology 3. If using CEMS or vent meter is not 
an option, use the inlet or outlet gas flow rate of the acid gas 
removal unit to calculate emissions for CO<INF>2</INF> using Equation 
W-4 of this section.

[[Page 74492]]

[GRAPHIC] [TIFF OMITTED] TR30NO10.176

Where:

E<INF>a,CO2</INF> = Annual volumetric CO<INF>2</INF> emissions at 
actual condition, in cubic feet per year.
V = Total annual volume of natural gas flow into or out of the AGR 
unit in cubic feet per year at actual condition as determined using 
methods specified in paragraph (d)(5) of this section.
[alpha] = Factor is 1 if the outlet stream flow is measured. Factor 
is 0 if the inlet stream flow is measured.
Vol<INF>I</INF> = Volume fraction of CO<INF>2</INF> content in 
natural gas into the AGR unit as determined in paragraph (d)(7) of 
this section.
Vol<INF>O</INF> = Volume fraction of CO<INF>2</INF> content in 
natural gas out of the AGR unit as determined in paragraph (d)(8) of 
this section.

    (4) Calculation Methodology 4. Calculate emissions using any 
standard simulation software packages, such as AspenTech HYSYS[supreg] 
and API 4679 AMINECalc, that uses the Peng-Robinson equation of state, 
and speciates CO<INF>2</INF> emissions. A minimum of the following 
determined for typical operating conditions over the calendar year by 
engineering estimate and process knowledge based on best available data 
must be used to characterize emissions:
    (i) Natural gas feed temperature, pressure, and flow rate.
    (ii) Acid gas content of feed natural gas.
    (iii) Acid gas content of outlet natural gas.
    (iv) Unit operating hours, excluding downtime for maintenance or 
standby.
    (v) Exit temperature of natural gas.
    (vi) Solvent pressure, temperature, circulation rate, and weight.
    (5) Record the gas flow rate of the inlet and outlet natural gas 
stream of an AGR unit using a meter according to methods set forth in 
Sec.  98.234(b). If you do not have a continuous flow meter, either 
install a continuous flow meter or use an engineering calculation to 
determine the flow rate.
    (6) If continuous gas analyzer is not available on the vent stack, 
either install a continuous gas analyzer or take quarterly gas samples 
from the vent gas stream to determine Vol<INF>CO2</INF> according to 
methods set forth in Sec.  98.234(b).
    (7) If a continuous gas analyzer is installed on the inlet gas 
stream, then the continuous gas analyzer results must be used. If 
continuous gas analyzer is not available, either install a continuous 
gas analyzer or take quarterly gas samples from the inlet gas stream to 
determine Vol<INF>I</INF> according to methods set forth in Sec.  
98.234(b).
    (8) Determine volume fraction of CO<INF>2</INF> content in natural 
gas out of the AGR unit using one of the methods specified in paragraph 
(d)(8) of this section.
    (i) If a continuous gas analyzer is installed on the outlet gas 
stream, then the continuous gas analyzer results must be used. If a 
continuous gas analyzer is not available, you may install a continuous 
gas analyzer.
    (ii) If a continuous gas analyzer is not available or installed, 
quarterly gas samples may be taken from the outlet gas stream to 
determine Vol<INF>O</INF> according to methods set forth in Sec.  
98.234(b).
    (iii) Use sales line quality specification for CO<INF>2</INF> in 
natural gas.
    (9) Calculate CO<INF>2</INF> volumetric emissions at standard 
conditions using calculations in paragraph (t) of this section.
    (10) Mass CO<INF>2</INF> emissions shall be calculated from 
volumetric CO<INF>2</INF> emissions using calculations in paragraph (v) 
of this section.
    (11) Determine if emissions from the AGR unit are recovered and 
transferred outside the facility. Adjust the emission estimated in 
paragraphs (d)(1) through (d)(10) of this section downward by the 
magnitude of emission recovered and transferred outside the facility.
    (e) Dehydrator vents. For dehydrator vents, calculate annual 
CH<INF>4</INF>, CO<INF>2</INF> and N<INF>2</INF>O (when flared) 
emissions using calculation methodologies described in paragraphs 
(e)(1) or (e)(2) of this section.
    (1) Calculation Methodology 1. Calculate annual mass emissions from 
dehydrator vents with throughput greater than or equal to 0.4 million 
standard cubic feet per day using a software program, such as AspenTech 
HYSYS[supreg] or GRI-GLYCalc, that uses the Peng-Robinson equation of 
state to calculate the equilibrium coefficient, speciates 
CH<INF>4</INF> and CO<INF>2</INF> emissions from dehydrators, and has 
provisions to include regenerator control devices, a separator flash 
tank, stripping gas and a gas injection pump or gas assist pump. A 
minimum of the following parameters determined by engineering estimate 
based on best available data must be used to characterize emissions 
from dehydrators:
    (i) Feed natural gas flow rate.
    (ii) Feed natural gas water content.
    (iii) Outlet natural gas water content.
    (iv) Absorbent circulation pump type (natural gas pneumatic/air 
pneumatic/electric).
    (v) Absorbent circulation rate.
    (vi) Absorbent type: including 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 and pressure.
    (xi) Wet natural gas composition. Determine this parameter by 
selecting one of the methods described under paragraph (e)(2)(xi) of 
this section.
    (A) Use the wet natural gas composition as defined in paragraph 
(u)(2)(i) of this section.
    (B) If wet natural gas composition cannot be determined using 
paragraph (u)(2)(i) of this section, select a representative analysis.
    (C) You may use an appropriate standard method published by a 
consensus-based standards organization if such a method exists or you 
may use an industry standard practice as specified in Sec.  
98.234(b)(1) to sample and analyze wet natural gas composition.
    (D) If only composition data for dry natural gas is available, 
assume the wet natural gas is saturated.
    (2) Calculation Methodology 2. Calculate annual CH<INF>4</INF> and 
CO<INF>2</INF> emissions from glycol dehydrators with throughput less 
than 0.4 million cubic feet per day using Equation W-5 of this section:
[GRAPHIC] [TIFF OMITTED] TR30NO10.177

Where:

E<INF>s,i</INF> = Annual total volumetric GHG emissions (either 
CO<INF>2</INF> or CH<INF>4</INF>) at standard conditions in cubic 
feet.
EF<INF>i</INF> = Population emission factors for glycol dehydrators 
in thousand standard cubic feet per dehydrator per year. Use 74.5 
for CH<INF>4</INF> and 3.26 for CO<INF>2</INF> at 68[deg]F and 14.7 
psia or 73.4 for CH<INF>4</INF> and 3.21 for CO<INF>2</INF> at 
60[deg]F and 14.7 psia.
Count = Total number of glycol dehydrators with throughput less than 
0.4 million cubic feet.
1000 = Conversion of EF<INF>i</INF> in thousand standard cubic to 
cubic feet.


[[Page 74493]]


    (3) Determine if dehydrator unit has vapor recovery. Adjust the 
emissions estimated in paragraphs (e)(1) or (e)(2) of this section 
downward by the magnitude of emissions captured.
    (4) Calculate annual emissions from dehydrator vents to flares or 
regenerator fire-box/fire tubes as follows:
    (A) Use the dehydrator vent volume and gas composition as 
determined in paragraphs (e)(1) and (e)(2) of this section.
    (B) Use the calculation methodology of flare stacks in paragraph 
(n) of this section to determine dehydrator vent emissions from the 
flare or regenerator combustion gas vent.
    (5) 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-6 of this section. 
Desiccant dehydrators covered in (e)(5) of this section do not have to 
report emissions under (i) of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.178

Where:

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

    (6) Both CH<INF>4</INF> and CO<INF>2</INF> volumetric and mass 
emissions shall be calculated from volumetric natural gas emissions 
using calculations in paragraphs (u) and (v) of this section.
    (f) Well venting for liquids unloadings. Calculate CO<INF>2</INF> 
and CH<INF>4</INF> emissions from well venting for liquids unloading 
using one of the calculation methodologies described in paragraphs 
(f)(1), (f)(2) or (f)(3) of this section.
    (1) Calculation Methodology 1. For one well of each unique well 
tubing diameter and producing horizon/formation combination in each gas 
producing field (see Sec.  98.238 for the definition of 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-7 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.179

Where:

E<INF>a,n</INF> = Annual natural gas emissions at actual conditions 
in cubic feet.
T<INF>h,t</INF> = Cumulative amount of time in hours of venting from 
all wells of the same tubing diameter (t) and producing horizon (h)/
formation combination during the year.
FR<INF>h,t</INF> = Average flow rate in cubic feet per hour of the 
measured well venting for the duration of the liquids unloading, 
under actual conditions as determined in paragraph (f)(1)(i) of this 
section.

    (i) Determine the well vent average flow rate as specified under 
paragraph (f)(1)(i) of this section.
    (A) The average flow rate per hour of venting is calculated for 
each unique tubing diameter and producing horizon/formation combination 
in each producing field by averaging the recorded flow rates for the 
recorded time of one representative well venting to the atmosphere.
    (B) This average flow rate is applied to all wells in the field 
that have the same tubing diameter and producing horizon/formation 
combination, for the number of hours of venting these wells.
    (C) A new average flow rate is calculated every other calendar year 
for each reporting field and horizon starting the first calendar year 
of data collection.
    (ii) Calculate natural gas volumetric emissions at standard 
conditions using calculations in paragraph (t) of this section.
    (2) Calculation Methodology 2. Calculate emissions from each well 
venting for liquids unloading using Equation W-8 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.180

Where:

E<INF>a,n</INF> = Annual natural gas emissions at actual conditions, 
in cubic feet/year.
0.37x10<SUP>-3</SUP> = {3.14 (pi)/4{time} /{14.7*144{time}  (psia 
converted to pounds per square feet).
CD = Casing diameter (inches).
WD = Well depth to first producing horizon (feet).
SP = Shut-in pressure (psia).
N<INF>V</INF> = Number of vents per year.
SFR = Average sales flow rate of gas well in cubic feet per hour.
HR = Hours that the well was left open to the atmosphere during 
unloading.
1.0 = Hours for average well to blowdown casing volume at shut-in 
pressure.
Z = If HR is less than 1.0 then Z is equal to 0. If HR is greater 
than or equal to 1.0 then Z is equal to 1.

    (i) Calculate natural gas volumetric emissions at standard 
conditions using calculations in paragraph (t) of this section.
    (ii) [Reserved]
    (3) Calculation Methodology 3. Calculate emissions from each well 
venting to the atmosphere for liquids unloading with plunger lift 
assist using Equation W-9 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.181


[[Page 74494]]


Where:

E<INF>a,n</INF> = Annual natural gas emissions at actual conditions, 
in cubic feet/year.
0.37x10<SUP>-3</SUP> = {3.14 (pi)/4{time} /{14.7*144{time}  (psia 
converted to pounds per square feet).
TD = Tubing diameter (inches).
WD = Tubing depth to plunger bumper (feet).
SP = Sales line pressure (psia).
N<INF>V</INF> = Number of vents per year.
SFR = Average sales flow rate of gas well in cubic feet per hour.
HR = Hours that the well was left open to the atmosphere during 
unloading.
0.5 = Hours for average well to blowdown tubing volume at sales line 
pressure.
Z = If HR is less than 0.5 then Z is equal to 0. If HR is greater 
than or equal to 0.5 then Z is equal to 1.

    (i) Calculate natural gas volumetric emissions at standard 
conditions using calculations in paragraph (t) of this section.
    (ii) [Reserved]
    (4) Both CH<INF>4</INF> and CO<INF>2</INF> volumetric and mass 
emissions shall be calculated from volumetric natural gas emissions 
using calculations in paragraphs (u) and (v) of this section.
    (g) Gas well venting during completions and workovers from 
hydraulic fracturing. Calculate CH<INF>4</INF>, CO<INF>2</INF> and 
N<INF>2</INF>O (when flared) annual emissions from gas well venting 
during completions involving hydraulic fracturing in wells and well 
workovers using Equation W-10 of this section. Both CH<INF>4</INF> and 
CO<INF>2</INF> volumetric and mass emissions shall be calculated from 
volumetric total gas emissions using calculations in paragraphs (u) and 
(v) of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.182

Where:

E<INF>a,n</INF> = Annual volumetric total gas emissions in cubic 
feet at standard conditions from gas well venting during completions 
following hydraulic fracturing.
T = Cumulative amount of time in hours of all well completion 
venting in a field during the year reporting.
FR = Average flow rate in cubic feet per hour, under actual 
conditions, converted to standard conditions, as required in 
paragraph (g)(1) of this section.
EnF = Volume of CO<INF>2</INF> or N<INF>2</INF> injected gas in 
cubic feet at standard conditions that was injected into the 
reservoir during an energized fracture job. If the fracture process 
did not inject gas into the reservoir, then EnF is 0. If injected 
gas is CO<INF>2</INF> then EnF is 0.
SG = Volume of natural gas in cubic feet at standard conditions that 
was recovered into a sales pipeline. If no gas was recovered for 
sales, SG is 0.

    (1) The average flow rate for gas well venting to the atmosphere or 
to a flare during well completions and workovers from hydraulic 
fracturing shall be determined using either of the calculation 
methodologies described in this paragraph (g)(1) of this section.
    (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 (digital or analog) shall be installed on the 
vent line, ahead of a flare if used, to measure the backflow venting 
event according to methods set forth in Sec.  98.234(b).
    (A) The average flow rate in cubic feet per hour of venting to the 
atmosphere or routed to a flare is determined from the flow recording 
over the period of backflow venting.
    (B) The respective flow rates are applied to all well completions 
in the producing field and to all well workovers in the producing field 
for the total number of hours of venting of each of these wells.
    (C) New flow rates for completions and workovers are measured every 
other calendar year for each reporting gas producing field and gas 
producing geologic horizon in each gas producing field starting in the 
first calendar year of data collection.
    (D) Calculate total volumetric flow rate at standard conditions 
using calculations in paragraph (t) of this section.
    (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 well flowing pressure upstream (and downstream in subsonic 
flow) of a well choke according to methods set forth in Sec.  98.234(b) 
to calculate intermittent well flow rate of gas during venting to the 
atmosphere or a flare. Calculate emissions using Equation W-11 of this 
section for subsonic flow or Equation W-12 of this section for sonic 
flow:
[GRAPHIC] [TIFF OMITTED] TR30NO10.183

Where:

FR = Average flow rate in cubic feet per hour, under subsonic flow 
conditions.
A = Cross sectional area of orifice (m\2\).
P<INF>1</INF> = Upstream pressure (psia).
T<INF>u</INF> = Upstream temperature (degrees Kelvin).
P<INF>2</INF> = Downstream pressure (psia).
3430 = Constant with units of m\2\/(sec\2\ * K).
1.27*10\5\ = Conversion from m\3\/second to ft\3\/hour.
[GRAPHIC] [TIFF OMITTED] TR30NO10.184

Where:

FR = Average flow rate in cubic feet per hour, under sonic flow 
conditions.
A = Cross sectional area of orifice (m\2\).
T<INF>u</INF> = Upstream temperature (degrees Kelvin).
187.08 = Constant with units of m\2\/(sec\2\ * K).
1.27*10\5\ = Conversion from m\3\/second to ft\3\/hour.

    (A) The average flow rate in cubic feet per hour of venting across 
the choke is calculated for one well completion in each gas producing 
field and for one well workover in each gas producing field by 
averaging the gas flow rates during venting to the atmosphere or 
routing to a flare.
    (B) The respective flow rates are applied to all well completions 
in the gas producing field and to all well workovers in the gas 
producing field for the total number of hours of venting of each of 
these wells.
    (C) Flow rates for completions and workovers in each field shall be 
calculated once every two years for each

[[Page 74495]]

reporting gas producing field and geologic horizon in each gas 
producing field starting in the first calendar year of data collection.
    (D) Calculate total volumetric flow rate at standard conditions 
using calculations in paragraph (t) of this section.
    (2) The volume of CO<INF>2</INF> or N<INF>2</INF> injected into the 
well reservoir during energized hydraulic fractures will be measured 
using an appropriate meter as described in 98.234(b) or using receipts 
of gas purchases that are used for the energized fracture job.
    (i) Calculate gas volume at standard conditions using calculations 
in paragraph (t) of this section.
    (ii) [Reserved]
    (3) The volume of recovered completion gas sent to a sales line 
will be measured using existing company records. If data does not exist 
on sales gas, then an appropriate meter as described in 98.234(b) may 
be used.
    (i) Calculate gas volume at standard conditions using calculations 
in paragraph (t) of this section.
    (ii) [Reserved]
    (4) Both CH<INF>4</INF> and CO<INF>2</INF> volumetric and mass 
emissions shall be calculated from volumetric total emissions using 
calculations in paragraphs (u) and (v) of this section.
    (5) Determine if the well completion or workover from hydraulic 
fracturing recovered gas with purpose designed equipment that separates 
saleable gas from the backflow, and sent this gas to a sales line (e.g. 
reduced emissions completion).
    (i) Use the factor SG in Equation W-10 of this section, to adjust 
the emissions estimated in paragraphs (g)(1) through (g)(4) of this 
section by the magnitude of emissions captured using reduced emission 
completions as determined by engineering estimate based on best 
available data.
    (ii) [Reserved]
    (6) Calculate annual emissions from gas well venting during well 
completions and workovers from hydraulic fracturing to flares as 
follows:
    (i) Use the total gas well venting volume during well completions 
and workovers as determined in paragraph (g) 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 using hydraulic fracturing emissions from the 
flare. This adjustment to emissions from completions using flaring 
versus completions without flaring accounts for the conversion of 
CH<INF>4</INF> to CO<INF>2</INF> in the flare.
    (h) Gas well venting during completions and workovers without 
hydraulic fracturing. Calculate CH<INF>4</INF>, CO<INF>2</INF> and 
N<INF>2</INF>O (when flared) emissions from each gas well venting 
during well completions and workovers not involving hydraulic 
fracturing and well workovers not involving hydraulic fracturing using 
Equation W-13 of this section:
[GRAPHIC] [TIFF OMITTED] TR30NO10.185

Where:

E<INF>a,n</INF> = Annual natural gas emissions in cubic feet at 
actual conditions from gas well venting during well completions and 
workovers without hydraulic fracturing.
N<INF>wo</INF> = Number of workovers per field not involving 
hydraulic fracturing in the reporting year.
EF<INF>wo</INF> = Emission Factor for non-hydraulic fracture well 
workover venting in actual cubic feet per workover. EF<INF>wo</INF> 
= 2,454 standard cubic feet per well workover without hydraulic 
fracturing.
f = Total number of well completions without hydraulic fracturing in 
a field.
V<INF>f</INF> = Average daily gas production rate in cubic feet per 
hour of each well completion without hydraulic fracturing. This is 
the total annual gas production volume divided by total number of 
hours the wells produced to the sales line. For completed wells that 
have not established a production rate, you may use the average flow 
rate from the first 30 days of production. In the event that the 
well is completed less than 30 days from the end of the calendar 
year, the first 30 days of the production straddling the current and 
following calendar years shall be used.
T<INF>f</INF> = Time each well completion without hydraulic 
fracturing was venting in hours during the year.

    (1) Calculate natural gas volumetric emissions at standard 
conditions using calculations in paragraph (t) of this section.
    (2) Both CH<INF>4</INF> and CO<INF>2</INF> volumetric and mass 
emissions shall be calculated from volumetric natural gas emissions 
using calculations in paragraphs (u) and (v) of this section.
    (3) Calculate annual emissions from gas well venting during well 
completions and workovers not involving hydraulic fracturing to flares 
as follows:
    (i) Use the gas well venting volume during well completions and 
workovers as determined in paragraph (h) 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 without hydraulic fracturing from 
the flare.
    (i) Blowdown vent stacks. Calculate CO<INF>2</INF> and 
CH<INF>4</INF> blowdown vent stack emissions from depressurizing 
equipment to the atmosphere (excluding depressurizing to a flare, over-
pressure relief, operating pressure control venting and blowdown of 
non-GHG gases; desiccant dehydrator blowdown venting before reloading 
is covered in paragraph (e)(5) of this section) as follows:
    (1) Calculate the total volume (including pipelines, compressor 
case or cylinders, manifolds, suction bottles, discharge bottles, and 
vessels) between isolation valves determined by engineering estimate 
based on best available data.
    (2) If the total volume between isolation valves is greater than or 
equal to 50 standard cubic feet, retain logs of the number of blowdowns 
for each equipment type (including but not limited to compressors, 
vessels, pipelines, headers, fractionators, and tanks). Blowdown 
volumes smaller than 50 standard cubic feet are exempt from reporting 
under paragraph (i) of this section.
    (3) Calculate the total annual venting emissions for each equipment 
type using Equation W-14 of this section:
[GRAPHIC] [TIFF OMITTED] TR30NO10.186


[[Page 74496]]


Where:

E<INF>s,n</INF> = Annual natural gas venting emissions at standard 
conditions from blowdowns in cubic feet.
N = Number of repetitive blowdowns for each equipment type of a 
unique volume in calendar year.
V<INF>v</INF> = Total volume of blowdown equipment chambers 
(including pipelines, compressors and vessels) between isolation 
valves in cubic feet.
C = Purge factor that is 1 if the equipment is not purged or zero if 
the equipment is purged using non-GHG gases.
T<INF>s</INF> = Temperature at standard conditions ([deg]F).
T<INF>a</INF> = Temperature at actual conditions in the blowdown 
equipment chamber ([deg]F).
P<INF>s</INF> = Absolute pressure at standard conditions (psia).
P<INF>a</INF> = Absolute pressure at actual conditions in the 
blowdown equipment chamber (psia).

    (4) Calculate both CH<INF>4</INF> and CO<INF>2</INF> mass emissions 
from volumetric natural gas emissions using calculations in paragraph 
(v) of this section.
    (5) Calculate total annual venting emissions for all blowdown vent 
stacks by adding all standard volumetric and mass emissions determined 
in Equation W-14 and paragraph (i)(4) of this section.
    (j) Onshore production storage tanks. Calculate CH<INF>4</INF>, 
CO<INF>2</INF> and N<INF>2</INF>O (when flared) emissions from 
atmospheric pressure fixed roof storage tanks receiving hydrocarbon 
produced liquids from onshore petroleum and natural gas production 
facilities (including stationary liquid storage not owned or operated 
by the reporter), calculate annual CH<INF>4</INF> and CO<INF>2</INF> 
emissions using any of the calculation methodologies described in this 
paragraph (j).
    (1) Calculation Methodology 1. For separators with oil throughput 
greater than or equal to 10 barrels per day. Calculate annual 
CH<INF>4</INF> and CO<INF>2</INF> emissions from onshore production 
storage tanks using operating conditions in the last wellhead gas-
liquid separator before liquid transfer to storage tanks. Calculate 
flashing emissions with a software program, such as AspenTech 
HYSYS[supreg] or API 4697 E&P Tank, that uses the Peng-Robinson 
equation of state, models flashing emissions, and speciates 
CH<INF>4</INF> and CO<INF>2</INF> emissions that will result when the 
oil from the separator enters an atmospheric pressure storage tank. A 
minimum of the following parameters determined for typical operating 
conditions over the year by engineering estimate and process knowledge 
based on best available data must be used to characterize emissions 
from liquid transferred to tanks.
    (i) Separator temperature.
    (ii) Separator pressure.
    (iii) Sales oil or stabilized oil API gravity.
    (iv) Sales oil or stabilized oil production rate.
    (v) Ambient air temperature.
    (vi) Ambient air pressure.
    (vii) Separator oil composition and Reid vapor pressure. If this 
data is not available, determine these parameters by selecting one of 
the methods described under paragraph (j)(1)(viii) of this section.
    (A) If separator oil composition and Reid vapor pressure default 
data are provided with the software program, select the default values 
that most closely match your separator pressure first, and API gravity 
secondarily.
    (B) If separator oil composition and Reid vapor pressure data are 
available through your previous analysis, select the latest available 
analysis that is representative of produced crude oil or condensate 
from the field.
    (C) Analyze a representative sample of separator oil in each field 
for oil composition and Reid vapor pressure using an appropriate 
standard method published by a consensus-based standards organization.
    (2) Calculation Methodology 2. Calculate annual CH<INF>4</INF> and 
CO<INF>2</INF> emissions from onshore production storage tanks for 
wellhead gas-liquid separators with oil throughput greater than or 
equal to 10 barrels per day by assuming that all of the CH<INF>4</INF> 
and CO<INF>2</INF> in solution at separator temperature and pressure is 
emitted from oil sent to storage tanks. You may use an appropriate 
standard method published by a consensus-based standards organization 
if such a method exists or you may use an industry standard practice as 
described in Sec.  98.234(b)(1) to sample and analyze separator oil 
composition at separator pressure and temperature.
    (3) Calculation Methodology 3. For wells with oil production 
greater than or equal to 10 barrels per day that flow directly to 
atmospheric storage tanks without passing through a wellhead separator, 
calculate CH<INF>4</INF> and CO<INF>2</INF> emissions by either of the 
methods in paragraph (j)(3) of this section:
    (i) If well production oil and gas compositions are available 
through your previous analysis, select the latest available analysis 
that is representative of produced oil and gas from the field and 
assume all of the CH<INF>4</INF> and CO<INF>2</INF> in both oil and gas 
are emitted from the tank.
    (ii) If well production oil and gas compositions are not available, 
use default oil and gas compositions in software programs, such as API 
4697 E&P Tank, that most closely match your well production gas/oil 
ratio and API gravity and assume all of the CH<INF>4</INF> and 
CO<INF>2</INF> in both oil and gas are emitted from the tank.
    (4) Calculation Methodology 4. For wells with oil production 
greater than or equal to 10 barrels per day that flow to a separator 
not at the well pad, calculate CH<INF>4</INF> and CO<INF>2</INF> 
emissions by either of the methods in paragraph (j)(4) of this section:
    (i) If well production oil and gas compositions are available 
through your previous analysis, select the latest available analysis 
that is representative of oil at separator pressure determined by best 
available data and assume all of the CH<INF>4</INF> and CO<INF>2</INF> 
in the oil is emitted from the tank.
    (ii) If well production oil composition is not available, use 
default oil composition in software programs, such as API 4697 E&P 
Tank, that most closely match your well production API gravity and 
pressure in the off-well pad separator determined by best available 
data. Assume all of the CH<INF>4</INF> and CO<INF>2</INF> in the oil 
phase is emitted from the tank.
    (5) Calculation Methodology 5. For well pad gas-liquid separators 
and for wells flowing off a well pad without passing through a gas-
liquid separator with throughput less than 10 barrels per day use 
Equation W-15 of this section:
[GRAPHIC] [TIFF OMITTED] TR30NO10.187


Where:

E<INF>s,i</INF> = Annual total volumetric GHG emissions (either 
CO<INF>2</INF> or CH<INF>4</INF>) at standard conditions in cubic 
feet.
EF<INF>i</INF> = Populations emission factor for separators and 
wells in thousand standard cubic feet per separator or well per 
year, for crude oil use 4.3 for CH<INF>4</INF> and 2.9 for 
CO<INF>2</INF> at 68 [deg]F and 14.7 psia, and for gas condensate 
use 17.8 for CH<INF>4</INF> and 2.9 for CO<INF>2</INF> at 68 [deg]F 
and 14.7 psia.
Count = Total number of separators and wells with throughput less 
than 10 barrels per day.

    (6) Determine if the storage tank receiving your separator oil has 
a vapor recovery system.
    (i) Adjust the emissions estimated in paragraphs (j)(1) through 
(j)(5) of this section downward by the magnitude of emissions recovered 
using a vapor recovery system as determined by engineering estimate 
based on best available data.
    (ii) [Reserved]
    (7) Determine if the storage tank receiving your separator oil is 
sent to flare(s).
    (i) Use your separator flash gas volume and gas composition as 
determined in this section.
    (ii) Use the calculation methodology of flare stacks in paragraph 
(n) of this

[[Page 74497]]

section to determine your contribution to storage tank emissions from 
the flare.
    (8) Calculate emissions from occurrences of well pad gas-liquid 
separator liquid dump valves not closing during the calendar year by 
using Equation W-16 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.188

Where:

E<INF>s,i</INF> = Annual total volumetric GHG emissions at standard 
conditions from each storage tank in cubic feet.
E<INF>n</INF> = Storage tank emissions as determined in Calculation 
Methodologies 1, 2, or 5 in paragraphs (j)(1) through (j)(5) of this 
section (with wellhead separators) during time T<INF>n</INF> in 
cubic feet per hour.
T<INF>n</INF> = Total time the dump valve is not closing properly in 
the calendar year in hours. T<INF>n</INF> is estimated by 
maintenance or operations records (records) such that when a record 
shows the valve to be open improperly, it is assumed the valve was 
open for the entire time period preceding the record starting at 
either the beginning of the calendar year or the previous record 
showing it closed properly within the calendar year. If a subsequent 
record shows it is closing properly, then assume from that time 
forward the valve closed properly until either the next record of it 
not closing properly or, if there is no subsequent record, the end 
of the calendar year.
CF<INF>n</INF> = Correction factor for tank emissions for time 
period T<INF>n</INF> is 3.87 for crude oil production. Correction 
factor for tank emissions for time period T<INF>n</INF> is 5.37 for 
gas condensate production. Correction factor for tank emissions for 
time period T<INF>n</INF> is 1.0 for periods when the dump valve is 
closed.
E<INF>t</INF> = Storage tank emissions as determined in Calculation 
Methodologies 1, 2, or 3 in paragraphs (j)(1) through (j)(5) of this 
section at maintenance or operations during the time the dump valve 
is closing properly (ie. 8760-T<INF>n</INF>) in cubic feet per hour.

    (9) Calculate both CH<INF>4</INF> and CO<INF>2</INF> mass emissions 
from volumetric natural gas emissions using calculations in paragraph 
(v) of this section.
    (k) Transmission storage tanks. For condensate storage tanks, 
either water or hydrocarbon, without vapor recovery or thermal control 
devices in onshore natural gas transmission compression facilities 
calculate CH<INF>4</INF>, CO<INF>2</INF> and N<INF>2</INF>O (when 
flared) annual emissions from compressor scrubber dump valve leakage as 
follows:
    (1) Monitor the tank vapor vent stack annually 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. Or you may annually 
monitor leakage through compressor scrubber dump valve(s) into the tank 
using an acoustic leak detection device according to methods set forth 
in Sec.  98.234(a)(5).
    (2) If the tank vapors are continuous for 5 minutes, or the 
acoustic leak detection device detects a leak, then use one of the 
following two methods in paragraph (k)(2) of this section to quantify 
emissions:
    (i) Use a meter, such as a turbine meter, to estimate tank vapor 
volumes according to methods set forth in Sec.  98.234(b). If you do 
not have a continuous flow measurement device, you may install a flow 
measuring device on the tank vapor vent stack.
    (ii) Use an acoustic leak detection device on each scrubber dump 
valve connected to the tank according to the method set forth in Sec.  
98.234(a)(5).
    (iii) Use the appropriate gas composition in paragraph (u)(2)(iii) 
of this section.
    (3) If the leaking dump valve(s) is fixed following leak detection, 
the annual emissions shall be calculated from the beginning of the 
calendar year to the time the valve(s) is repaired.
    (4) Calculate emissions from storage tanks to flares as follows:
    (i) Use the storage tank emissions volume and gas composition as 
determined in either paragraph (j)(1)of this section or with an 
acoustic leak detection device in paragraphs (k)(1) through (k)(3) 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 CH<INF>4,</INF> 
CO<INF>2</INF> and N<INF>2</INF>O (when flared) well testing venting 
and flaring emissions as follows:
    (1) Determine the gas to oil ratio (GOR) of the hydrocarbon 
production from each well tested.
    (2) If GOR cannot be determined from your available data, then you 
must measure quantities reported in this section according to one of 
the two procedures in paragraph (l)(2) of this section to determine 
GOR:
    (i) You may use an appropriate standard method published by a 
consensus-based standards organization if such a method exists.
    (ii) Or you may use an industry standard practice as described in 
Sec.  98.234(b).
    (3) Estimate venting emissions using Equation W-17 of this section.
    [GRAPHIC] [TIFF OMITTED] TR30NO10.189
    
Where:

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

    (4) Calculate natural gas volumetric emissions at standard 
conditions using calculations in paragraph (t) of this section.
    (5) Calculate both CH<INF>4</INF> and CO<INF>2</INF> volumetric and 
mass emissions from volumetric natural gas emissions using calculations 
in paragraphs (u) and (v) of this section.
    (6) 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 CH<INF>4</INF>, 
CO<INF>2</INF> and N<INF>2</INF>O (when flared) associated gas venting 
and flaring emissions not in conjunction with well testing (refer to 
paragraph (l): Well testing venting and flaring of this section) as 
follows:
    (1) Determine the GOR of the hydrocarbon production from each well 
whose associated natural gas is vented or flared. If GOR from each well 
is not available, the GOR from a cluster of wells in the same field 
shall be used.

[[Page 74498]]

    (2) If GOR cannot be determined from your available data, then use 
one of the two procedures in paragraph (m)(2) of this section to 
determine GOR:
    (i) You may use an appropriate standard method published by a 
consensus-based standards organization if such a method exists.
    (ii) Or you may use an industry standard practice as described in 
Sec.  98.234(b).
    (3) Estimate venting emissions using Equation W-18 of this section.
    [GRAPHIC] [TIFF OMITTED] TR30NO10.190
    

Where:

E<INF>a,n</INF> = Annual volumetric natural gas emissions from 
associated gas venting under actual 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 = Volume of oil produced in barrels in the calendar year during 
which associated gas was vented or flared.

    (4) Calculate natural gas volumetric emissions at standard 
conditions using calculations in paragraph (t) of this section.
    (5) Calculate both CH<INF>4</INF> and CO<INF>2</INF> volumetric and 
mass emissions from volumetric natural gas emissions using calculations 
in paragraphs (u) and (v) of this section.
    (6) Calculate emissions from associated natural gas to flares as 
follows:
    (i) Use the associated natural gas volume and gas composition as 
determined in paragraph (m)(1) through (4) of this section.
    (ii) Use the calculation methodology of flare stacks in paragraph 
(n) of this section to determine associated gas emissions from the 
flare.
    (n) Flare stack emissions. Calculate CO<INF>2</INF>, 
CH<INF>4</INF>, and N<INF>2</INF>O emissions from a flare stack as 
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 all of the flare gas is not measured by the existing flow 
measurement device, then the flow not measured can be estimated using 
engineering calculations based on best available data or company 
records. If you do not have a continuous flow measurement device on the 
flare, you can install a flow measuring device on the flare or use 
engineering calculations based on process knowledge, company records, 
and best available data.
    (2) If you have a continuous gas composition analyzer on gas to the 
flare, you must use these compositions in calculating emissions. If you 
do not have a continuous gas composition analyzer on gas to the flare, 
you must use the appropriate gas compositions for each stream of 
hydrocarbons going to the flare as follows:
    (i) For onshore natural gas production, determine natural gas 
composition using (u)(2)(i) of this section.
    (ii) For onshore natural gas processing, when the stream going to 
flare is natural gas, use the GHG mole percent in feed natural gas for 
all streams upstream of the de-methanizer or dew point control, and GHG 
mole percent in facility specific residue gas to transmission pipeline 
systems for all emissions sources downstream of the de-methanizer 
overhead or dew point control for onshore natural gas processing 
facilities.
    (iii) When the stream going to the flare is a hydrocarbon product 
stream, such as ethane, propane, butane, pentane-plus and mixed light 
hydrocarbons, then use a representative composition from the source for 
the stream determined by engineering calculation based on process 
knowledge and best available data.
    (3) Determine flare combustion efficiency from manufacturer. If not 
available, assume that flare combustion efficiency is 98 percent.
    (4) Calculate GHG volumetric emissions at actual conditions using 
Equations W-19, W-20, and W-21 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.191

Where:

E<INF>a,CH</INF>4(un-combusted) = Contribution of annual un-
combusted CH<INF>4</INF> emissions from flare stack in cubic feet, 
under actual conditions.
E<INF>a,CO</INF>2(un-combusted) = Contribution of annual un-
combusted CO<INF>2</INF> emissions from flare stack in cubic feet, 
under actual conditions.
E<INF>a,CO</INF>2(combusted) = Contribution of annual combusted 
CO<INF>2</INF> emissions from flare stack in cubic feet, under 
actual conditions.
V<INF>a</INF> = Volume of gas sent to flare in cubic feet, during 
the year.
[eta] = Fraction of gas combusted by a burning flare (default is 
0.98). For gas sent to an unlit flare, [eta] is zero.
X<INF>CH</INF>4 = Mole fraction of CH<INF>4</INF> in gas to the 
flare.
X<INF>CO</INF>2 = Mole fraction of CO<INF>2</INF> in gas to the 
flare.
Y<INF>j</INF> = Mole fraction of gas hydrocarbon constituents j 
(such as methane, ethane, propane, butane, and pentanes-plus).
R<INF>j</INF> = Number of carbon atoms in the 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 CH<INF>4</INF> and CO<INF>2</INF> mass emissions 
from volumetric CH<INF>4</INF> and CO<INF>2</INF> emissions using 
calculation in paragraph (v) of this section.
    (7) Calculate total annual emission from flare stacks by summing 
Equation W-40, Equation W-19, Equation W-20 and Equation W-21 of this 
section.
    (8) Calculate N<INF>2</INF>O emissions from flare stacks using 
Equation W-40 in paragraph (z) of this section.
    (9) The flare emissions determined under paragraph (n) of this 
section must be corrected for flare emissions calculated and reported 
under other paragraphs of this section to avoid double counting of 
these emissions.
    (o) Centrifugal compressor venting. Calculate CH<INF>4</INF>, 
CO<INF>2</INF> and N<INF>2</INF>O (when flared) emissions from both wet 
seal and dry seal centrifugal compressor vents as follows:
    (1) For each centrifugal compressor covered by Sec.  98.232 (d)(2), 
(e)(2), (f)(2), (g)(2), and (h)(2) you must conduct an annual 
measurement in the operating mode in which it is found. Measure 
emissions from all vents (including emissions manifolded to common 
vents)

[[Page 74499]]

including wet seal oil degassing vents, unit isolation valve vents, and 
blowdown valve vents. Record emissions from the following vent types in 
the specified compressor modes during the annual measurement.
    (i) Operating mode, blowdown valve leakage through the blowdown 
vent, wet seal and dry seal compressors.
    (ii) Operating mode, wet seal oil degassing vents.
    (iii) Not operating, depressurized mode, unit isolation valve 
leakage through open blowdown vent, without blind flanges, wet seal and 
dry seal compressors.
    (A) For the not operating, depressurized mode, each compressor must 
be measured at least once in any three consecutive calendar years. If a 
compressor is not operated and has blind flanges in place throughout 
the 3 year period, measurement is not required in this mode. If the 
compressor is in standby depressurized mode without blind flanges in 
place and is not operated throughout the 3 year period, it must be 
measured in the standby depressurized mode.
    (2) For wet seal oil degassing vents, determine vapor volumes sent 
to an atmospheric vent or flare, using a temporary meter such as a vane 
anemometer or permanent flow meter according to 98.234(b) of this 
section. If you do not have a permanent flow meter, you may install a 
permanent flow meter on the wet seal oil degassing tank vent.
    (3) For blowdown valve leakage and unit isolation valve leakage to 
open ended vents, you can use one of the following methods: Calibrated 
bagging or high volume sampler according to methods set forth in Sec.  
98.234(c) and Sec.  98.234(d), respectively. For through valve leakage, 
such as isolation valves, you may use an acoustic leak detection device 
according to methods set forth in Sec.  98.234(a). If you do not have a 
flow meter, you may install a port for insertion of a temporary meter, 
or a permanent flow meter, on the vents.
    (4) Estimate annual emissions using the flow measurement and 
Equation W-22 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.192

Where:

E<INF>s,i,m</INF> = Annual GHG<INF>i</INF> (either CH<INF>4</INF> or 
CO<INF>2</INF>) volumetric emissions at standard conditions, in 
cubic feet.
MT<INF>m</INF> = Measured gas emissions in standard cubic feet per 
hour.
T<INF>m</INF> = Total time the compressor is in the mode for which 
E<INF>s,i</INF> is being calculated, in the calendar year in hours.
M<INF>i,m</INF> = Mole fraction of GHG<INF>i</INF> in the vent gas; 
use the appropriate gas compositions in paragraph (u)(2) of this 
section.
B<INF>m</INF> = Fraction of operating time that the vent gas is sent 
to vapor recovery or fuel gas as determined by keeping logs of the 
number of operating hours for the vapor recovery system and the time 
that vent gas is directed to the fuel gas system or sales.

    (5) Calculate annual emissions from each centrifugal compressor 
using Equation W-23 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.193

Where:

E<INF>s,i</INF> = Annual total volumetric GHG emissions at standard 
conditions from each centrifugal compressor in cubic feet.
EF<INF>m</INF> = Reporter emission factor for each mode m, in cubic 
feet per hour, from Equation W-24 of this section as calculated in 
paragraph 6.
T<INF>m</INF> = Total time in hours per year the compressor was in 
each mode, as listed in paragraph (o)(1)(i) through (o)(1)(iii).
GHG<INF>i</INF> = For onshore natural gas processing facilities, 
concentration of GHG <INF>i</INF>, CH<INF>4</INF> or CO<INF>2</INF>, 
in produced natural gas or feed natural gas; for other facilities 
listed in Sec.  98.230(a)(4) through (a)(8),GHG<INF>i</INF> equals 
1.

    (6) You shall use the flow measurements of operating mode wet seal 
oil degassing vent, operating mode blowdown valve vent and not 
operating depressurized mode isolation valve vent for all the 
reporter's compressor modes not measured in the calendar year to 
develop the following emission factors using Equation W-24 of this 
section for each emission source and mode as listed in paragraph 
(o)(1)(i) through (o)(1)(iii).
[GRAPHIC] [TIFF OMITTED] TR30NO10.194

Where:

EF<INF>m</INF> = Reporter emission factors for compressor in the 
three modes m (as listed in paragraph (o)(1)(i) through (o)(1)(iii)) 
in cubic feet per hour.
MT<INF>m</INF> = Flow Measurements from all centrifugal compressor 
vents in each mode in (o)(1)(i) through (o)(1)(iii) of this section 
in cubic feet per hour.
Count<INF>m</INF> = Total number of compressors measured.
m = Compressor mode as listed in paragraph (o)(1)(i) through 
(o)(1)(iii).

    (i) The emission factors must be calculated annually. You must use 
all measurements from the current calendar year and the preceding two 
calendar years, totaling three consecutive calendar years of 
measurements in paragraph (o)(6) of this section.
    (ii) [Reserved]
    (7) Onshore petroleum and natural gas production shall calculate 
emissions from centrifugal compressor wet seal oil degassing vents as 
follows:
[GRAPHIC] [TIFF OMITTED] TR30NO10.195


[[Page 74500]]


Where:

E<INF>s,i</INF> = Annual total volumetric GHG emissions at standard 
conditions from centrifugal compressor wet seals in cubic feet.
Count = Total number of centrifugal compressors for the reporter.
EF<INF>i</INF> = Emission factor for GHG <INF>i</INF>. Use 12.2 
million standard cubic feet per year per compressor for 
CH<INF>4</INF> and 538 thousand standard cubic feet per year per 
compressor for CO<INF>2</INF> at 68[deg]F and 14.7 psia or 12 
million standard cubic feet per year per compressor for 
CH<INF>4</INF> and 530 thousand standard cubic feet per year per 
compressor for CO<INF>2</INF> at 60[deg]F and 14.7 psia.

    (8) Calculate both CH<INF>4</INF> and CO<INF>2</INF> mass emissions 
from volumetric emissions using calculations in paragraph (v) of this 
section.
    (9) Calculate emissions from seal oil degassing vent vapors to 
flares as follows:
    (i) Use the seal oil degassing vent vapor volume and gas 
composition as determined in paragraphs (o)(5) 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 venting. Calculate CH<INF>4</INF> and 
CO<INF>2</INF> emissions from all reciprocating compressor vents as 
follows. For each reciprocating compressor covered in Sec.  
98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1) you must conduct an 
annual measurement for each compressor in the mode in which it is found 
during the annual measurement, except as specified in paragraph (p)(9) 
of this section. Measure emissions from (including emissions manifolded 
to common vents) reciprocating rod packing vents, unit isolation valve 
vents, and blowdown valve vents. Record emissions from the following 
vent types in the specified compressor modes during the annual 
measurement as follows:
    (1) Operating or standby pressurized mode, blowdown vent leakage 
through the blowdown vent stack.
    (2) Operating mode, reciprocating rod packing emissions.
    (3) Not operating, depressurized mode, unit isolation valve leakage 
through the blowdown vent stack, without blind flanges.
    (i) For the not operating, depressurized mode, each compressor must 
be measured at least once in any three consecutive calendar years if 
this mode is not found in the annual measurement. If a compressor is 
not operated and has blind flanges in place throughout the 3 year 
period, measurement is not required in this mode. If the compressor is 
in standby depressurized mode without blind flanges in place and is not 
operated throughout the 3 year period, it must be measured in the 
standby depressurized mode.
    (ii) [Reserved]
    (4) If reciprocating rod packing and blowdown vent are connected to 
an open-ended vent line 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 vents using either calibrated bagging or high 
volume sampler according to methods set forth in Sec.  98.234(c) and 
Sec.  98.234(d), respectively.
    (ii) Use a temporary meter such as a vane anemometer or a permanent 
meter such as an orifice meter to measure emissions from all vents 
(including emissions manifolded to a common vent) including rod packing 
vents and unit isolation valve leakage through blowdown vents according 
to methods set forth in Sec.  98.234(b). If you do not have a permanent 
flow meter, you may install a port for insertion of a temporary meter 
or a permanent flow meter on the vents. For through-valve leakage to 
open ended vents, such as unit isolation valves on not operating, 
depressurized compressors and blowdown valves on pressurized 
compressors, you may use an acoustic detection device according to 
methods set forth in Sec.  98.234(a).
    (5) If reciprocating rod packing is not equipped with a vent line 
use the following method to calculate emissions:
    (i) You must use the methods described in Sec.  98.234(a) to 
conduct annual leak detection of equipment leaks from the packing case 
into an open distance piece, or from the compressor crank case breather 
cap or other vent with a closed distance piece.
    (ii) Measure emissions found in paragraph (p)(5)(i) of this section 
using an appropriate meter, or calibrated bag, or high volume sampler 
according to methods set forth in Sec.  98.234(b), (c), and (d), 
respectively.
    (6) Estimate annual emissions using the flow measurement and 
Equation W-26 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.196

Where:

E<INF>s,i,m</INF> = Annual GHG i (either CH<INF>4</INF> or 
CO<INF>2</INF>) volumetric emissions at standard conditions, in 
cubic feet.
MT<INF>m</INF> = Measured gas emissions in standard cubic feet per 
hour.
T<INF>m</INF> = Total time the compressor is in the mode for which 
E<INF>s,i,m</INF> is being calculated, in the calendar year in 
hours.
M<INF>i,m</INF> = Mole fraction of GHG i in gas; use the appropriate 
gas compositions in paragraph (u)(2) of this section.

    (7) Calculate annual emissions from each reciprocating compressor 
using Equation W-27 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.197

Where:

E<INF>s,i</INF> = Annual total volumetric GHG emissions at standard 
conditions from each reciprocating compressor in cubic feet.
EF<INF>m</INF> = Reporter emission factor for each mode, m, in cubic 
feet per hour, from Equation W-28 of this section as calculated in 
paragraph (p)(7)(i) of this section.
T<INF>m</INF> = Total time in hours per year the compressor was in 
each mode, m, as listed in paragraph (p)(1) through (p)(3).
GHG<INF>i</INF> = For onshore natural gas processing facilities, 
concentration of GHG i, CH<INF>4</INF> or CO<INF>2</INF>, in 
produced natural gas or feed natural gas; for other facilities 
listed in Sec.  98.230(a)(4) through (a)(8), GHG<INF>i</INF> equals 
1.
m = Compressor mode as listed in paragraph (p)(1) through (p)(3).

    (i) You shall use the flow meter readings from measurements of 
operating and standby pressurized blowdown vent, operating mode vents, 
not operating depressurized isolation valve vent for all the reporter's 
compressor modes not measured in the

[[Page 74501]]

calendar year to develop the following emission factors using Equation 
W-28 of this section for each mode as listed in paragraph (p)(1) 
through (p)(3).
[GRAPHIC] [TIFF OMITTED] TR30NO10.198

Where:

EF<INF>m</INF> = Reporter emission factors for compressor in the 
three modes, m, in cubic feet per hour.
MT<INF>m</INF> = Meter readings from all reciprocating compressor 
vents in each and mode, m, in cubic feet per hour.
Count<INF>m</INF> = Total number of compressors measured in each 
mode, m.
m = Compressor mode as listed in paragraph (p)(1) through (p)(3).

    (A) You must combine emissions for blowndown vents, measured in the 
operating and standby pressurized modes.
    (B) The emission factors must be calculated annually. You must use 
all measurements from the current calendar year and the preceding two 
calendar years, totaling three consecutive calendar years of 
measurements.
    (ii) [Reserved]
    (8) Determine if the reciprocating compressor vent vapors are sent 
to a vapor recovery system.
    (i) Adjust the emissions estimated in paragraphs (p)(7) of this 
section downward by the magnitude of emissions recovered using a vapor 
recovery system as determined by engineering estimate based on best 
available data.
    (ii) [Reserved]
    (9) Onshore petroleum and natural gas production shall calculate 
emissions from reciprocating compressors as follows:
[GRAPHIC] [TIFF OMITTED] TR30NO10.199

Where:

E<INF>s,i</INF> = Annual total volumetric GHG emissions at standard 
conditions from reciprocating compressors in cubic feet.
Count = Total number of reciprocating compressors for the reporter.
EF<INF>i</INF> = Emission factor for GHG i. Use 9.63 thousand 
standard cubic feet per year per compressor for CH<INF>4</INF> and 
0.535 thousand standard cubic feet per year per compressor for 
CO<INF>2</INF> at 68[deg]F and 14.7 psia or 9.48 thousand standard 
cubic feet per year per compressor for CH<INF>4</INF> and 0.527 
thousand standard cubic feet per year per compressor for 
CO<INF>2</INF> at 60[deg]F and 14.7 psia.

    (10) Estimate CH<INF>4</INF> and CO<INF>2</INF> 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 leak detection(s) of 
equipment leaks from all sources listed in Sec.  98.232(d)(7), (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 
CH<INF>4</INF> plus CO<INF>2</INF> by weight. Emissions sources in 
streams with gas content less than 10 percent CH<INF>4</INF> plus 
CO<INF>2</INF> by weight do not need to be reported. Tubing systems 
equal to or less than one half inch diameter are exempt from the 
requirements of this paragraph (q) and do not need to be reported. If 
equipment leaks are detected for sources listed in this paragraph (q), 
calculate emissions using Equation W-30 of this section for each source 
with equipment leaks.
[GRAPHIC] [TIFF OMITTED] TR30NO10.200

Where:

E<INF>s,i</INF> = Annual total volumetric GHG emissions at standard 
conditions from each equipment leak source in cubic feet.
x = Total number of this type of emissions source found to be 
leaking during T<INF>x</INF>.
EF<INF>s</INF> = Leaker emission factor for specific sources listed 
in Table W-2 through Table W-7 of this subpart.
GHG<INF>i</INF> = For onshore natural gas processing facilities, 
concentration of GHG<INF>i</INF>, CH<INF>4</INF> or CO<INF>2</INF>, 
in the total hydrocarbon of the feed natural gas; for other 
facilities listed in Sec.  98.230(a)(4) through (a)(8), 
GHG<INF>i</INF> equals 1 for CH<INF>4</INF> and 1.1 x 
10<SUP>-2</SUP> for CO<INF>2</INF>.
T<INF>x</INF> = The total time the component was found leaking and 
operational, in hours. If one leak detection survey is conducted, 
assume the component was leaking for the entire calendar year. If 
multiple leak detection surveys are conducted, assume that the 
component found to be leaking has been leaking since the previous 
survey or the beginning of the calendar year. For the last leak 
detection survey in the calendar year, assume that all leaking 
components continue to leak until the end of the calendar year.

    (1) You must select to conduct either one leak detection survey in 
a calendar year or multiple complete leak detection surveys in a 
calendar year. The number of leak detection surveys selected must be 
conducted during the calendar year.
    (2) Calculate GHG mass emissions in carbon dioxide equivalent at 
standard conditions using calculations in paragraph (v) of this 
section.
    (3) Onshore natural gas processing facilities shall use the 
appropriate default leaker emission factors listed in Table W-2 of this 
subpart for equipment leaks detected from valves, connectors, open 
ended lines, pressure relief valves, and meters.
    (4) Onshore natural gas transmission compression facilities shall 
use the appropriate default leaker emission factors listed in Table W-3 
of this subpart for equipment leaks detected from valves, connectors, 
open ended lines, pressure relief valves, and meters.
    (5) 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 equipment leaks detected from valves, 
connectors, open ended lines, pressure relief valves, and meters.
    (6) LNG storage facilities shall use the appropriate default leaker 
emission factors listed in Table W-5 of this subpart for equipment 
leaks detected from valves, pump seals, connectors, and other.
    (7) LNG import and export facilities shall use the appropriate 
default leaker emission factors listed in Table W-6 of this subpart for 
equipment leaks detected from valves, pump seals, connectors, and 
other.
    (8) Natural gas distribution facilities for above ground meters and 
regulators at city gate stations at custody transfer, shall use the 
appropriate default leaker emission factors listed in Table W-7 of this 
subpart for equipment leak detected from connectors, block valves, 
control valves, pressure relief valves, orifice meters, regulators, and 
open ended lines.
    (r) Population count and emission factors. This paragraph applies 
to emissions sources listed in Sec.  98.232 (c)(21), (f)(5), (g)(3), 
(h)(4), (i)(2), (i)(3), (i)(4) and (i)(5), on streams with gas content 
greater than 10 percent CH<INF>4</INF> plus CO<INF>2</INF> by weight. 
Emissions sources in streams with gas content less than 10 percent 
CH<INF>4</INF> plus CO<INF>2</INF> by weight do not need to be 
reported. Tubing systems equal or less than one half inch diameter are 
exempt from the requirements of paragraph (r) of this section and do 
not need to be reported. Calculate emissions from all sources listed in 
this paragraph using Equation W-31 of this section.

[[Page 74502]]

[GRAPHIC] [TIFF OMITTED] TR30NO10.201


Where:

E<INF>s,i</INF> = Annual volumetric GHG emissions at standard 
conditions from each equipment leak source in cubic feet.
Count<INF>s</INF> = Total number of this type of emission source at 
the facility. Average component counts are provided by major 
equipment piece in Tables W-1B and Table W-1C of this subpart. Use 
average component counts as appropriate for operations in Eastern 
and Western U.S., according to Table W-1D of this subpart.
EF<INF>s</INF> = Population emission factor for the specific source, 
s listed in Table W-1A and Tables W-3 through Table W-7 of this 
subpart. Use appropriate population emission factor for operations 
in Eastern and Western U.S., according to Table W-1D of this 
subpart. EF for non-custody transfer city gate stations is 
determined in Equation W-32.
GHG<INF>i</INF> = For onshore petroleum and natural gas production 
facilities and onshore natural gas processing facilities, 
concentration of GHG i, CH<INF>4</INF> or CO<INF>2</INF>, in 
produced natural gas or feed natural gas; for other facilities 
listed in Sec.  98.230(a)(4) through (a)(8), GHG<INF>i</INF> equals 
1 for CH<INF>4</INF> and 1.1 x 10<SUP>-2</SUP> for CO<INF>2</INF>.
T<INF>s</INF> = Total time the specific source s associated with the 
equipment leak emission was operational in the calendar year, in 
hours.

    (1) Calculate both CH<INF>4</INF> and CO<INF>2</INF> mass emissions 
from volumetric emissions using calculations in paragraph (v) of this 
section.
    (2) Onshore petroleum and natural gas production facilities shall 
use the appropriate default population emission factors listed in Table 
W-1A of this subpart for equipment leaks from valves, connectors, open 
ended lines, pressure relief valves, pump, flanges, and other. Major 
equipment and components associated with gas wells are considered gas 
service components in reference to Table 1-A of this subpart and major 
natural gas equipment in reference to Table W-1B of this subpart. Major 
equipment and components associated with crude oil wells are considered 
crude service components in reference to Table 1-A of this subpart and 
major crude oil equipment in reference to Table W-1C of this subpart. 
Where facilities conduct EOR operations the emissions factor listed in 
Table W-1A of this subpart shall be used to estimate all streams of 
gases, including recycle CO<INF>2</INF> stream. The component count can 
be determined using either of the methodologies described in this 
paragraph (r)(2). The same methodology must be used for the entire 
calendar year.
    (i) Component Count Methodology 1. For all onshore petroleum and 
natural gas production operations in the facility perform the following 
activities:
    (A) Count all major equipment listed in Table W-1B and Table W-1C 
of this subpart.
    (B) Multiply major equipment counts by the average component counts 
listed in Table W-1B and W-1C of this subpart for onshore natural gas 
production and onshore oil production, respectively. Use the 
appropriate factor in Table W-1A of this subpart for operations in 
Eastern and Western U.S. according to the mapping in Table W-1D of this 
subpart.
    (ii) Component Count Methodology 2. Count each component 
individually for the facility. Use the appropriate factor in Table W-1A 
of this subpart for operations in Eastern and Western U.S. according to 
the mapping in Table W-1D of this subpart.
    (3) Underground natural gas storage facilities for storage 
wellheads shall use the appropriate default population emission factors 
listed in Table W-4 of this subpart for equipment leak from connectors, 
valves, pressure relief valves, and open ended lines.
    (4) LNG storage facilities shall use the appropriate default 
population emission factors listed in Table W-5 of this subpart for 
equipment leak from vapor recovery compressors.
    (5) LNG import and export facilities shall use the appropriate 
default population emission factor listed in Table W-6 of this subpart 
for equipment leak from vapor recovery compressors.
    (6) Natural gas distribution facilities shall use the appropriate 
emission factors as described in paragraph (r)(6) of this section.
    (i) Below grade meters and regulators; mains; and services, shall 
use the appropriate default population emission factors listed in Table 
W-7 of this subpart.
    (ii) Above grade meters and regulators at city gate stations not at 
custody transfer as listed in Sec.  98.232(i)(2), shall use the total 
volumetric GHG emissions at standard conditions for all equipment leak 
sources calculated in paragraph (q)(8) of this section to develop 
facility emission factors using Equation W-32 of this section. The 
calculated facility emission factor from Equation W-32 of this section 
shall be used in Equation W-31 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.202

Where:

EF = Facility emission factor for a meter at above grade M&R at city 
gate stations not at custody transfer in cubic feet per meter per 
year.
E<INF>s,i</INF> = Annual volumetric GHG emissions at standard 
condition from all equipment leak sources at all above grade M&R 
city gate stations at custody transfer, from paragraph (q) of this 
section.
Count = Total number of meter runs at all above grade M&R city gate 
stations at custody transfer.

    (s) Offshore petroleum and natural gas production facilities. 
Report CO<INF>2,</INF> CH<INF>4</INF>, and N<INF>2</INF>O emissions for 
offshore petroleum and natural gas production from all equipment leaks, 
vented emission, and flare emission source types as identified in the 
data collection and emissions estimation study conducted by BOEMRE in 
compliance with 30 CFR 250.302 through 304.
    (1) Offshore production facilities under BOEMRE jurisdiction shall 
report the same annual emissions as calculated and reported by BOEMRE 
in data collection and emissions estimation study published by BOEMRE 
referenced in 30 CFR 250.302 through 304 (GOADS).
    (i) For any calendar year that does not overlap with the most 
recent BOEMRE emissions study publication year, report the most recent 
BOEMRE reported emissions data published by BOEMRE referenced in 30 CFR 
250.302 through 304 (GOADS). Adjust emissions based on the operating 
time for the facility relative to the operating time in the most recent 
BOEMRE published study.
    (ii) [Reserved]
    (2) Offshore production facilities that are not under BOEMRE 
jurisdiction shall use monitoring methods and calculation methodologies 
published by BOEMRE referenced in 30 CFR 250.302 through 304 to 
calculate and report emissions (GOADS).
    (i) For any calendar year that does not overlap with the most 
recent BOEMRE emissions study publication, report the

[[Page 74503]]

most recent reported emissions data with emissions adjusted based on 
the operating time for the facility relative to operating time in the 
previous reporting period.
    (ii) [Reserved]
    (3) If BOEMRE discontinues or delays their data collection effort 
by more than 4 years, then offshore reporters shall once in every 4 
years use the most recent BOEMRE data collection and emissions 
estimation methods to report emission from the facility sources.
    (4) For either first or subsequent year reporting, offshore 
facilities either within or outside of BOEMRE jurisdiction that were 
not covered in the previous BOEMRE data collection cycle shall use the 
most recent BOEMRE data collection and emissions estimation methods 
published by BOEMRE referenced in 30 CFR 250.302 through 304 to 
calculate and report emissions (GOADS) to report emissions.
    (t) Volumetric emissions. Calculate volumetric emissions at 
standard conditions as specified in paragraphs (t)(1) or (2) of this 
section determined by engineering estimate based on best available data 
unless otherwise specified.
    (1) Calculate natural gas volumetric emissions at standard 
conditions by converting actual temperature and pressure of natural gas 
emissions to standard temperature and pressure of natural gas using 
Equation W-33 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.203

Where:

E<INF>s,n</INF> = Natural gas volumetric emissions at standard 
temperature and pressure (STP) conditions in cubic feet.
E<INF>a,n</INF> = Natural gas volumetric emissions at actual 
conditions in cubic feet.
T<INF>s</INF> = Temperature at standard conditions ([deg]F).
T<INF>a</INF> = Temperature at actual emission conditions ([deg]F).
P<INF>s</INF> = Absolute pressure at standard conditions (psia).
P<INF>a</INF> = Absolute pressure at actual conditions (psia).

    (2) Calculate GHG volumetric emissions at standard conditions by 
converting actual temperature and pressure of GHG emissions to standard 
temperature and pressure using Equation W-34 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.204

Where:

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

    (u) GHG volumetric emissions. Calculate GHG volumetric emissions at 
standard conditions as specified in paragraphs (u)(1) and (2) of this 
section determined by engineering estimate based on best available data 
unless otherwise specified.
    (1) Estimate CH<INF>4</INF> and CO<INF>2</INF> emissions from 
natural gas emissions using Equation W-35 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.205


Where:

E<INF>s,i</INF> = GHG i (either CH<INF>4</INF> or CO<INF>2</INF>) 
volumetric emissions at standard conditions in cubic feet.
E<INF>s,n</INF> = Natural gas volumetric emissions at standard 
conditions in cubic feet.
M<INF>i</INF> = Mole fraction of GHG i in the natural gas.

    (2) For Equation W-35 of this section, the mole fraction, 
M<INF>i</INF>, shall be the annual average mole fraction for each 
facility, as specified in paragraphs (u)(2)(i) through (vii) of this 
section.
    (i) GHG mole fraction in produced natural gas for onshore petroleum 
and natural gas production facilities. If you have a continuous gas 
composition analyzer for produced natural gas, you must use these 
values for determining the mole fraction. If you do not have a 
continuous gas composition analyzer, then you must use your most recent 
gas composition based on available sample analysis of the field.
    (ii) GHG mole fraction in feed natural gas for all emissions 
sources upstream of the de-methanizer or dew point control and GHG mole 
fraction in facility specific residue gas to transmission pipeline 
systems for all emissions sources downstream of the de-methanizer 
overhead or dew point control for onshore natural gas processing 
facilities. If you have a continuous gas composition analyzer on feed 
natural gas, you must use these values for determining the mole 
fraction. If you do not have a continuous gas composition analyzer, 
then annual samples must be taken according to methods set forth in 
Sec.  98.234(b).
    (iii) GHG mole fraction in transmission pipeline natural gas that 
passes through the facility for onshore natural gas transmission 
compression facilities.
    (iv) GHG mole fraction in natural gas stored in underground natural 
gas storage facilities.
    (v) GHG mole fraction in natural gas stored in LNG storage 
facilities.
    (vi) GHG mole fraction in natural gas stored in LNG import and 
export facilities.
    (vii) GHG mole fraction 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-36 of this 
section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.206


[[Page 74504]]


Where:

Mass<INF>s,i</INF> = GHG i (either CH<INF>4</INF> or CO<INF>2</INF>) 
mass emissions at standard conditions in metric tons 
CO<INF>2</INF>e.
E<INF>s,i</INF> = GHG i (either CH<INF>4</INF> or CO<INF>2</INF>) 
volumetric emissions at standard conditions, in cubic feet.
[rho]<INF>i</INF> = Density of GHG i. Use 0.0538 kg/ft\3\ for 
CO<INF>2</INF> and N<INF>2</INF>O, and 0.0196 kg/ft\3\ for 
CH<INF>4</INF> at 68[deg]F and 14.7 psia or 0.0530 kg/ft\3\ for 
CO<INF>2</INF> and N<INF>2</INF>O, and 0.0193 kg/ft\3\ for 
CH<INF>4</INF> at 60[deg]F and 14.7 psia.
GWP = Global warming potential, 1 for CO<INF>2,</INF> 21 for 
CH<INF>4</INF>, and 310 for N<INF>2</INF>O.

    (w) EOR injection pump blowdown. Calculate CO<INF>2</INF> pump 
blowdown emissions as follows:
    (1) Calculate the total volume in cubic feet (including pipelines, 
manifolds and vessels) between isolation valves.
    (2) Retain logs of the number of blowdowns per calendar year.
    (3) Calculate the total annual venting emissions using Equation W-
37 of this section:
[GRAPHIC] [TIFF OMITTED] TR30NO10.207

Where:

Mass<INF>c,i</INF> = Annual EOR injection gas venting emissions in 
metric tons at critical conditions ``c'' from blowdowns.
N = Number of blowdowns for the equipment in the calendar year.
V<INF>v</INF> = Total volume in cubic feet of blowdown equipment 
chambers (including pipelines, manifolds and vessels) between 
isolation valves.
R<INF>c</INF> = Density of critical phase EOR injection gas in kg/
ft\3\. You may use an appropriate standard method published by a 
consensus-based standards organization if such a method exists or 
you may use an industry standard practice to determine density of 
super critical EOR injection gas.
GHG<INF>i</INF> = Mass fraction of GHG<INF>i</INF> in critical phase 
injection gas.
1 x 10<SUP>-3</SUP> = Conversion factor from kilograms to metric 
tons.

    (x) EOR hydrocarbon liquids dissolved CO<INF>2</INF>. Calculate 
dissolved CO<INF>2</INF> in hydrocarbon liquids produced through EOR 
operations as follows:
    (1) Determine the amount of CO<INF>2</INF> retained in hydrocarbon 
liquids after flashing in tankage at STP conditions. Annual samples 
must be taken according to methods set forth in Sec.  98.234(b) to 
determine retention of CO<INF>2</INF> in hydrocarbon liquids 
immediately downstream of the storage tank. Use the annual analysis for 
the calendar year.
    (2) Estimate emissions using Equation W-38 of this section.
    [GRAPHIC] [TIFF OMITTED] TR30NO10.208
    
Where:

Mass<INF>s,CO2</INF> = Annual CO<INF>2</INF> emissions from 
CO<INF>2</INF> retained in hydrocarbon liquids produced through EOR 
operations beyond tankage, in metric tons.
S<INF>hl</INF> = Amount of CO<INF>2</INF> retained in hydrocarbon 
liquids in metric tons per barrel, under standard conditions.
V<INF>hl</INF> = Total volume of hydrocarbon liquids produced at the 
EOR operations in barrels in the calendar year.

    (y) [Reserved]
    (z) Onshore petroleum and natural gas production and natural gas 
distribution combustion emissions. Calculate CO<INF>2</INF> 
CH<INF>4,</INF>and N<INF>2</INF>O combustion-related emissions from 
stationary or portable equipment as follows:
    (1) If the fuel combusted in the stationary or portable equipment 
is listed in Table C-1 of subpart C of this part, or is a blend of 
fuels listed in Table C-1, use the Tier 1 methodology described in 
subpart C of this part (General Stationary Fuel Combustion Sources). If 
the fuel combusted is natural gas and is pipeline quality and has a 
minimum high heat value of 950 Btu per standard cubic foot, then the 
natural gas emission factor and high heat values listed in Tables C-1 
and C-2 of this part may be used.
    (2) For fuel combustion units that combust field gas or process 
vent gas, or any blend of field gas or process vent gas and fuels 
listed in Table C-1 of subpart C of this part, calculate combustion 
emissions as follows:
    (i) If you have a continuous flow meter on the combustion unit, you 
must use the measured flow volumes to calculate the total flow of gas 
to the unit. If you do not have a permanent flow meter on the 
combustion unit, you may install a permanent flow meter on the 
combustion unit, or use company records or engineering calculations 
based on best available data on heat duty or horsepower to estimate 
volumetric unit gas flow.
    (ii) If you have a continuous gas composition analyzer on fuel to 
the combustion unit, you must use these compositions for determining 
the concentration of gas hydrocarbon constituent in the flow of gas to 
the unit. If you do not have a continuous gas composition analyzer on 
gas to the combustion unit, you must use the appropriate gas 
compositions for each stream of hydrocarbons going to the combustion 
unit as specified in paragraph (u)(2)(i) of this section.
    (iii) Calculate GHG volumetric emissions at actual conditions using 
Equations W-39 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.209

Where:

E<INF>a,CO</INF>2 = Contribution of annual emissions from portable 
or stationary fuel combustion sources in cubic feet, under actual 
conditions.
V<INF>a</INF> = Volume of gas sent to combustion unit in cubic feet, 
during the year.
Y<INF>j</INF> = Concentration of gas hydrocarbon constituents j 
(such as methane, ethane, propane, butane, and pentanes plus).
R<INF>j</INF> = Number of carbon atoms in the gas hydrocarbon 
constituent j; 1 for methane, 2 for ethane, 3 for propane, 4 for 
butane, and 5 for pentanes plus).

    (3) External fuel combustion sources with a rated heat capacity 
equal to or less than 5 mmBtu/hr do not need to report combustion 
emissions. You must report the type and number of each external fuel 
combustion unit.
    (4) Calculate GHG volumetric emissions at standard conditions using 
calculations in paragraph (t) of this section.
    (5) Calculate both combustion-related CH<INF>4</INF> and 
CO<INF>2</INF> mass emissions from volumetric CH<INF>4</INF> and 
CO<INF>2</INF> emissions using calculation in paragraph (v) of this 
section.

[[Page 74505]]

    (6) Calculate N<INF>2</INF>O mass emissions using Equation W-40 of 
this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.210

Where:

N<INF>2</INF>O = Annual N<INF>2</INF>O emissions from the combustion 
of a particular type of fuel (metric tons).
Fuel = Mass or volume of the fuel combusted (mass or volume per 
year, choose appropriately to be consistent with the units of HHV).
HHV = High heat value of the fuel from paragraphs (z)(8)(i), 
(z)(8)(ii) or (z)(8)(iii) of this section (units must be consistent 
with Fuel).
EF = Use 1.0 x 10<SUP>-</SUP>\4\ kg N<INF>2</INF>O/mmBtu.
1 x 10<SUP>-</SUP>\3\ = Conversion factor from kilograms to metric 
tons.

    (i) For fuels listed in Table C-1 of subpart C of this part, use 
the provided default HHV in the table.
    (ii) For field gas or process vent gas, use 1.235 x 
10<SUP>-</SUP>\3\ mmBtu/scf for HHV.
    (iii) For fuels not listed in Table C-1 of subpart C of this part 
and not field gas or process vent gas, you must use the methodology set 
forth in the Tier 2 methodology described in subpart C of this part to 
determine HHV.


Sec.  98.234  Monitoring and QA/QC requirements.

    The GHG emissions data for petroleum and natural gas emissions 
sources must be quality assured as applicable as specified in this 
section. Offshore petroleum and natural gas production facilities shall 
adhere to the monitoring and QA/QC requirements as set forth in 30 CFR 
250.
    (a) You must use any of the methods described as follows in this 
paragraph to conduct leak detection(s) of equipment leaks and through-
valve leakage from all source types listed in Sec.  98.233(k), (o), (p) 
and (q) that occur during a calendar year, except as provided in 
paragraph (a)(4) of this section.
    (1) Optical gas imaging instrument. Use an optical gas imaging 
instrument for equipment leak detection in accordance with 40 CFR part 
60, subpart A, Sec.  60.18(i)(1) and (2) of the Alternative work 
practice for monitoring equipment leaks. Any emissions detected by the 
optical gas imaging instrument is a leak unless screened with Method 21 
(40 CFR part 60, appendix A-7) monitoring, in which case 10,000 ppm or 
greater is designated a leak. In addition, you must operate the optical 
gas imaging instrument to image the source types required by this 
subpart in accordance with the instrument manufacturer's operating 
parameters.
    (2) Method 21. Use the equipment leak detection methods in 40 CFR 
part 60, appendix A-7, Method 21. If using Method 21 monitoring, if an 
instrument reading of 10,000 ppm or greater is measured, a leak is 
detected. Inaccessible emissions sources, as defined in 40 CFR part 60, 
are not exempt from this subpart. Owners or operators must use 
alternative leak detection devices as described in paragraph(a)(1) of 
this section to monitor inaccessible equipment leaks or vented 
emissions.
    (3) Infrared laser beam illuminated instrument. Use an infrared 
laser beam illuminated instrument for equipment leak detection. Any 
emissions detected by the infrared laser beam illuminated instrument is 
a leak unless screened with Method 21 monitoring, in which case 10,000 
ppm or greater is designated a leak. In addition, you must operate the 
infrared laser beam illuminated instrument to detect the source types 
required by this subpart in accordance with the instrument 
manufacturer's operating parameters.
    (4) Optical gas imaging instrument. An optical gas imaging 
instrument must be used for all source types that are inaccessible and 
cannot be monitored without elevating the monitoring personnel more 
than 2 meters above a support surface.
    (5) Acoustic leak detection device. Use the acoustic leak detection 
device to detect through-valve leakage. When using the acoustic leak 
detection device to quantify the through-valve leakage, you must use 
the instrument manufacturer's calculation methods to quantify the 
through-valve leak. When using the acoustic leak detection device, if a 
leak of 3.1 scf per hour or greater is calculated, a leak is detected. 
In addition, you must operate the acoustic leak detection device to 
monitor the source valves required by this subpart in accordance with 
the instrument manufacturer's operating parameters.
    (b) You must operate and calibrate all flow meters, composition 
analyzers and pressure gauges used to measure quantities reported in 
Sec.  98.233 according to the procedures in Sec.  98.3(i) and the 
procedures in paragraph (b) of this section. You may use an appropriate 
standard method published by a consensus-based standards organization 
if such a method exists or you may use an industry standard practice. 
Consensus-based standards organizations include, but are not limited 
to, the following: ASTM International, the American National Standards 
Institute (ANSI), the American Gas Association (AGA), the American 
Society of Mechanical Engineers (ASME), the American Petroleum 
Institute (API), and the North American Energy Standards Board (NAESB).
    (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 CH<INF>4</INF> and CO<INF>2</INF> 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 positioning the instrument for complete capture of the 
equipment leak 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 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 CH<INF>4</INF> and CO<INF>2</INF> volumetric and mass 
emissions from volumetric natural gas emissions using the calculations 
in Sec.  98.233(u) and (v).

[[Page 74506]]

    (4) Calibrate the instrument at 2.5 percent methane with 97.5 
percent air and 100 percent CH<INF>4</INF> by using calibrated gas 
samples and by following manufacturer's instructions for calibration.
    (e) Peng Robinson Equation of State means the equation of state 
defined by Equation W-41 of this section:
[GRAPHIC] [TIFF OMITTED] TR30NO10.211

Where:

p = Absolute pressure.
R = Universal gas constant.
T = Absolute temperature.
V<INF>m</INF> = Molar volume.
[GRAPHIC] [TIFF OMITTED] TR30NO10.212

Where:

[omega] = Acentric factor of the species.
T<INF>c</INF> = Critical temperature.
P<INF>c</INF> = Critical pressure.

    (f) Special reporting provisions
    (1) Best available monitoring methods. EPA will allow owners or 
operators to use best available monitoring methods for parameters in 
Sec.  98.233 Calculating GHG Emissions as specified in paragraphs 
(f)(2), (f)(3), and (f)(4) of this section. If the reporter anticipates 
the potential need for best available monitoring for sources for which 
they need to petition EPA and the situation is unresolved at the time 
of the deadline, reporters should submit written notice of this 
potential situation to EPA by the specified deadline for requests to be 
considered. EPA reserves the right to review petitions after the 
deadline but will only consider and approve late petitions which 
demonstrate extreme or unusual circumstances. The Administrator 
reserves to right to request further information in regard to all 
petition requests. The owner or operator must use the calculation 
methodologies and equations in Sec.  98.233 Calculating GHG Emissions. 
Best available monitoring methods means any of the following methods 
specified in paragraph (f)(1) of this section:
    (i) Monitoring methods currently used by the facility that do not 
meet the specifications of this subpart.
    (ii) Supplier data.
    (iii) Engineering calculations.
    (iv) Other company records.
    (2) Best available monitoring methods for well-related emissions. 
During January 1, 2011 through June 30, 2011, owners or operators may 
use best available monitoring methods for any well-related data that 
cannot reasonably be measured according to the monitoring and QA/QC 
requirements of this subpart, and only where required measurements 
cannot be duplicated due to technical limitations after June 30, 2011. 
These well-related sources are:
    (i) Gas well venting during well completions and workovers with 
hydraulic fracturing as specified in Sec.  98.233(g).
    (ii) Well testing venting and flaring as specified in Sec.  
98.233(l).
    (3) Best available monitoring methods for specified activity data. 
During January 1, 2011 through June 30, 2011, owners or operators may 
use best available monitoring methods for activity data as listed below 
that cannot reasonably be obtained according to the monitoring and QA/
QC requirements of this subpart, specifically for events that generate 
data that can be collected only between January 1, 2011 and June 30, 
2011 and cannot be duplicated after June 30, 2011. These sources are:
    (i) Cumulative hours of venting, days, or times of operation in 
Sec.  98.233(e), (f), (g), (h), (l), (o), (p), (q), and (r).
    (ii) Number of blowdowns, completions, workovers, or other events 
in Sec.  98.233(f), (g), (h), (i), and (w).
    (iii) Cumulative volume produced, volume input or output, or volume 
of fuel used in paragraphs Sec.  98.233(d), (e), (j), (k), (l), (m), 
(n), (x), (y), and (z).
    (4) Best available monitoring methods for leak detection and 
measurement. The owner or operator may request use of best available 
monitoring methods between January 1, 2011 and December 31, 2011 for 
sources requiring leak detection and/or measurement. These sources 
include:
    (i) Reciprocating compressor rod packing venting in onshore natural 
gas processing, onshore natural gas transmission compression, 
underground natural gas storage, LNG storage, and LNG import and export 
equipment as specified in Sec.  98.232(d)(1), (e)(1), (f)(1), (g)(1), 
and (h)(1).
    (ii) Centrifugal compressor wet seal oil degassing venting in 
onshore natural gas processing, onshore natural gas transmission 
compression, underground natural gas storage, LNG storage, and LNG 
import and export equipment as specified in Sec.  98.232(d)(2), (e)(2), 
(f)(2), (g)(2), and (h)(2).
    (iii) Acid gas removal vent stacks in onshore petroleum and natural 
gas production and onshore natural gas processing as specified in Sec.  
98.232(c)(17) and (d)(6).
    (iv) Equipment leak emissions from valves, connectors, open ended 
lines, pressure relief valves, block valves, control valves, compressor 
blowdown valves, orifice meters, other meters, regulators, vapor 
recovery compressors, centrifugal compressor dry seals, and/or other 
equipment leaks in onshore

[[Page 74507]]

natural gas processing, onshore natural gas transmission compression, 
underground natural gas storage, LNG storage, LNG import and export 
equipment, and natural gas distribution as specified in Sec.  
98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1).
    (v) Condensate (oil and/or water) storage tanks in onshore natural 
gas transmission compression as specified in Sec.  98.232(e)(3).
    (5) Requests for the use of best available monitoring methods. The 
owner or operator may submit a request to the Administrator to use one 
or more best available monitoring methods.
    (i) No request or approval by the Administrator is necessary to use 
best available monitoring methods between January 1, 2011 and June 30, 
2011 for the sources specified in paragraph (f)(2) of this section.
    (ii) No request or approval by the Administrator is necessary to 
use best available monitoring methods between January 1, 2011 and June 
30, 2011 for the sources specified in paragraph (f)(3) of this section.
    (iii) Owners or operators must submit a request and receive 
approval by the Administrator to use best available monitoring methods 
between January 1, 2011 and December 31, 2011 for sources specified in 
paragraph (f)(4) of this section.
    (A) Timing of request. The request to use best available monitoring 
methods for paragraph (f)(4) of this section must be submitted to EPA 
no later than April 30, 2011.
    (B) Content of request. Requests must contain the following 
information for sources listed in paragraph (f)(4) of this section:
    (1) A list of specific source types and specific equipment, 
monitoring instrumentation, and/or services for which the request is 
being made and the locations where each piece of monitoring 
instrumentation will be installed or monitoring service will be 
supplied.
    (2) Identification of the specific rule requirements (by subpart, 
section, and paragraph number) for which the instrumentation or 
monitoring service is needed.
    (3) Documentation which demonstrates that the owner or operator 
made all reasonable efforts to obtain the information, services or 
equipment necessary to comply with subpart W reporting requirements, 
including evidence of specific service or equipment providers contacted 
and why services or information could not be obtained during 2011.
    (4) A description of the specific actions the facility will take to 
obtain and/or install the equipment or obtain the monitoring service as 
soon as reasonably feasible and the expected date by which the 
equipment will be obtained and operating or service will be provided.
    (C) Approval criteria. To obtain approval, the owner or operator 
must demonstrate to the Administrator's satisfaction that it does not 
own the required monitoring equipment, and it is not reasonably 
feasible to acquire, install, and operate a required piece of 
monitoring equipment or to obtain leak detection or measurement 
services in order to meet the requirements of this subpart for 2011.
    (iv) EPA does not anticipate a need to approve the use of best 
available monitoring methods for sources not listed in 
paragraphs(f)(2), (f)(3), and (f)(4) of this section; however, EPA will 
review such requests if submitted in accordance with paragraph 
(f)(5)(iv)(A)-(C) of this section.
    (A) Timing of request. The request to use best available monitoring 
methods for sources not listed in paragraphs (f)(2), (f)(3), and (f)(4) 
of this section must be submitted to EPA no later than April 30, 2011.
    (B) Content of request. Requests must contain the following 
information:
    (1) A list of specific source categories and parameters for which 
the owner or operator is seeking use of best available monitoring 
methods.
    (2) A description of the data collection methodologies that do not 
meet safety regulations, technical infeasibility, or specific laws or 
regulations that conflict with each specific source for which an owner 
or operator is requesting use of best available monitoring 
methodologies.
    (3) A detailed explanation and supporting documentation of how and 
when the owner or operator will receive the services or equipment to 
comply with all subpart W reporting requirements.
    (C) Approval criteria. To obtain approval, the owner or operator 
must demonstrate to the Administrator's satisfaction that the owner or 
operator faces unique safety, technical or legal issues rendering them 
unable to meet the requirements of this subpart for 2011.
    (6) Requests for extension of the use of best available monitoring 
methods through December 31, 2011 for sources in paragraph (f)(2) of 
this section. The owner or operator may submit a request to the 
Administrator to use one or more best available monitoring methods 
described in paragraph (f)(2) of this section beyond June 30, 2011.
    (i) Timing of request. The extension request must be submitted to 
EPA no later than April 30, 2011.
    (ii) Content of request. Requests must contain the following 
information:
    (A) A list of specific source types and specific equipment, 
monitoring instrumentation, contract modifications, and/or services for 
which the request is being made and the locations where each piece of 
monitoring instrumentation will be installed, monitoring service will 
be supplied, or contracts will be modified.
    (B) Identification of the specific rule requirements (by subpart, 
section, and paragraph number) for which the instrumentation, contract 
modification, or monitoring service is needed.
    (C) A description and applicable correspondence outlining the 
diligent efforts of the owner or operator in obtaining the needed 
equipment or service and why they could not be obtained and installed 
in a period of time enabling completion of applicable requirements of 
this subpart within the 2011 calendar year.
    (D) If the reason for the extension is that the owner or operator 
cannot collect data from a service provider or relevant organization in 
order for the owner or operator to meet requirements of this subpart 
for the 2011 calendar year, the owner or operator must demonstrate a 
good faith effort that it is not possible to obtain the necessary 
information, service or hardware which may include providing 
correspondence from specific service providers or other relevant 
entities to the owner or operator, whereby the service provider states 
that it is unable to provide the necessary data or services requested 
by the owner or operator that would enable the owner or operator to 
comply with subpart W reporting requirements by June 30, 2011.
    (E) A description of the specific actions the owner or operator 
will take to comply with monitoring requirements in 2012 and beyond.
    (iii) Approval criteria. To obtain approval, the owner or operator 
must demonstrate to the Administrator's satisfaction that it is not 
reasonably feasible to obtain the data necessary to meet the 
requirements of this subpart for the sources specified in paragraph 
(f)(2) of this section by June 30, 2011.
    (7) Requests for extension of the use of best available monitoring 
methods through December 31, 2011 for sources in paragraph (f)(3) of 
this section. The owner or operator may submit a request to the 
Administrator to use one or more best available monitoring methods 
described in paragraph (f)(3) of this section beyond June 30, 2011.

[[Page 74508]]

    (i) Timing of request. The extension request must be submitted to 
EPA no later than April 30, 2011.
    (ii) Content of request. Requests must contain the following 
information:
    (A) A list of specific source types for which data collection could 
not be implemented.
    (B) Identification of the specific rule requirements (by subpart, 
section, and paragraph number) for which the data collection could not 
be implemented.
    (C) A description of the data collection methodologies that do not 
meet safety regulations, technical infeasibility, or specific laws or 
regulations that conflict with each specific source for which an owner 
or operator is requesting use of best available monitoring 
methodologies for which data collection could not be implemented in the 
2011 calendar year.
    (iii) Approval criteria. To obtain approval, the owner or operator 
must demonstrate to the Administrator's satisfaction that it is not 
reasonably feasible to implement the data collection for the sources 
described in paragraph (f)(3) of this section for the methods required 
in this subpart by June, 30, 2011.
    (8) Requests for extension of the use of best available monitoring 
methods beyond 2011 for sources listed in paragraphs (f)(2), (f)(3), 
(f)(4), (f)(5)(iv) of this section and other sources in this subpart. 
EPA does not anticipate a need for approving the use of best available 
methods beyond December 31, 2011, except in extreme circumstances, 
which include safety, a requirement being technically infeasible or 
counter to other local, State, or Federal regulations.
    (i) Timing of request. The request to use best available monitoring 
methods for paragraphs (f)(2), (f)(3), (f)(4), (f)(5)(iv) of this 
section and sources not listed in paragraphs (f)(2), (f)(3), (f)(4), 
(f)(5)(iv) of this section must be submitted to EPA no later than 
September 30, 2011.
    (ii) Content of request. Requests must contain the following 
information:
    (iii) A list of specific source categories and parameters for which 
the owner or operator is seeking use of best available monitoring 
methods.
    (iv) A description of the data collection methodologies that do not 
meet safety regulations, technical infeasibility, or specific laws or 
regulations that conflict with each specific source for which an owner 
or operator is requesting use of best available monitoring 
methodologies.
    (v) A detailed explanation and supporting documentation of how and 
when the owner or operator will receive the services or equipment to 
comply with all of this subpart W reporting requirements.
    (C) Approval criteria. To obtain approval, the owner or operator 
must demonstrate to the Administrator's satisfaction that the owner or 
operator faces unique safety, technical or legal issues rendering them 
unable to meet the requirements of this subpart.


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 calendar year if missing 
data are not discovered until after December 31 of the year in which 
data are collected, until valid data for reporting is obtained. Data 
developed and/or collected in a subsequent calendar year to substitute 
for missing data cannot be used for that subsequent year's emissions 
estimation. Where missing data procedures are used for the previous 
year, at least 30 days must separate emissions estimation or 
measurements for the previous year and emissions estimation or 
measurements for the current year of data collection. For missing data 
which are continuously monitored or measured, (for example flow 
meters), or for missing temperature or pressure data that are required 
under Sec.  98.236, the reporter may use best available data for use in 
emissions determinations. The reporter must record and report the basis 
for the best available data in these cases.


Sec.  98.236  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain reported emissions and related information 
as specified in this section.
    (a) Report annual emissions separately for each of the industry 
segments listed in paragraphs (a)(1) through (8) of this section in 
metric tons CO<INF>2</INF>e per year at standard conditions. For each 
segment, report emissions from each source type Sec.  98.232(a) in the 
aggregate, unless specified otherwise. For example, an onshore natural 
gas production 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) Offshore petroleum and natural gas production is not required 
to report activity data and emissions for each aggregated source under 
Sec.  98.236(c). Reporting requirements for offshore petroleum and 
natural gas production is set forth by BOEMRE in compliance with 30 CFR 
250.302 through 304.
    (c) For each aggregated source, unless otherwise specified, report 
activity data and emissions (in metric tons CO<INF>2</INF>e per year at 
standard conditions) for each aggregated source type as follows:
    (1) For natural gas pneumatic devices (refer to Equation W-1 of 
Sec.  98.233), report the following:
    (i) Actual count and estimated count separately of natural gas 
pneumatic high bleed devices as applicable.
    (ii) Actual count and estimated count separately of natural gas 
pneumatic low bleed devices as applicable.
    (iii) Actual count and estimated count separately of natural gas 
pneumatic intermittent bleed devices as applicable.
    (iv) Report emissions collectively.
    (2) For natural gas driven pneumatic pumps (refer to Equation W-2 
of Sec.  98.233), report the following,
    (i) Count of natural gas driven pneumatic pumps.
    (ii) Report emissions collectively.
    (3) For each acid gas removal unit (refer to Equation W-3 and 
Equation W-4 of Sec.  98.233), report the following:
    (i) Total throughput off the acid gas removal unit using a meter or 
engineering estimate based on process knowledge or best available data 
in million cubic feet per year.
    (ii) For Calculation Methodology 1 and Calculation Methodology 2 of 
Sec.  98.233(d), fraction of CO<INF>2</INF> content in the vent from 
the acid gas removal unit (refer to Sec.  98.233(d)(6)).
    (iii) For Calculation Methodology 3 of Sec.  98.233(d), volume 
fraction of CO<INF>2</INF> content of natural gas into and out of the 
acid gas removal unit (refer to Sec.  98.233(d)(7) and (d)(8)).
    (iv) Report emissions from the AGR unit recovered and transferred 
outside the facility.
    (v) Report emissions individually.
    (4) For dehydrators, report the following:
    (i) For each Glycol dehydrator with a throughput greater than or 
equal to 0.4 MMscfd (refer to Sec.  98.233(e)(1)), report the 
following:

[[Page 74509]]

    (A) Glycol dehydrator feed natural gas flow rate in MMscfd, 
determined by engineering estimate based on best available data.
    (B) Glycol dehydrator absorbent circulation pump type.
    (C) Whether stripper gas is used in glycol dehydrator.
    (D) Whether a flash tank separator is used in glycol dehydrator.
    (E) Type of absorbent.
    (F) Total time the glycol dehydrator is operating in hours.
    (G) Temperature, in degrees Fahrenheit and pressure, in psig, of 
the wet natural gas.
    (H) Concentration of CH<INF>4</INF> and CO<INF>2</INF> in natural 
gas.
    (I) What vent gas controls are used (refer to Sec.  98.233(e)(3) 
and (e)(4)).
    (J) Report vent and flared emissions individually.
    (ii) For all glycol dehydrators with a throughput less than 0.4 
MMscfd (refer to Sec.  98.233, Equation W-5 of Sec.  98.233), report 
the following:
    (A) Count of glycol dehydrators.
    (B) Whether any vent gas controls are used (refer to Sec.  
98.233(e)(3) and (e)(4)).
    (C) Report vent emissions collectively.
    (iii) For absorbent desiccant dehydrators (refer to Equation W-6 of 
Sec.  98.233), report the following:
    (A) Count of desiccant dehydrators.
    (B) Report emissions collectively.
    (5) For well venting for liquids unloading (refer to Equations W-7, 
W-8 and W-9 of Sec.  98.233), report the following by field:
    (i) Count of wells vented to the atmosphere for liquids unloading.
    (ii) Count of plunger lifts.
    (iii) Cumulative number of unloadings vented to the atmosphere.
    (iv) Average flow rate of the measured well venting in cubic feet 
per hour (refer to Sec.  98.233(f)(1)(i)(A)).
    (v) Average casing diameter in inches.
    (vi) Report emissions collectively.
    (6) For well completions and workovers, report the following for 
each field:
    (i) For gas well completions and workovers with hydraulic 
fracturing (refer to Equation W-10 of Sec.  98.233):
    (A) Total count of completions in calendar year.
    (B) Average flow rate of the measured well completion venting in 
cubic feet per hour (refer to Sec.  98.233(g)(1)(i) or (g)(1)(ii)).
    (C) Total count of workovers in calendar year.
    (D) Average flow rate of the measured well workover venting in 
cubic feet per hour (refer to Sec.  98.233(g)(1)(i) or (g)(1)(ii)).
    (E) Total number of days of gas venting to the atmosphere during 
backflow for completion.
    (F) Total number of days of gas venting to the atmosphere during 
backflow for workovers.
    (G) Report number of completions and workovers employing reduced 
emissions completions and engineering estimate based on best available 
data of the amount of gas recovered to sales.
    (H) Report vent emissions collectively. Report flared emissions 
collectively.
    (ii) For gas well completions and workovers without hydraulic 
fracturing (refer to Equation W-13 of Sec.  98.233):
    (A) Total count of completions in calendar year.
    (B) Total count of workovers in calendar year.
    (C) Total number of days of gas venting to the atmosphere during 
backflow for completion.
    (D) Report vent emissions collectively. Report flared emissions 
collectively.
    (7) For each blowdown vent stack (refer to Equation W-14 of Sec.  
98.233), report the following:
    (i) Total number of blowdowns per equipment type in calendar year.
    (ii) Report emissions collectively per equipment type.
    (8) For gas emitted from produced oil sent to atmospheric tanks:
    (i) For wellhead gas-liquid separator with oil throughput greater 
than or equal to 10 barrels per day, using Calculation Methodology 1 
and 2 of Sec.  98.233(j), report the following by field:
    (A) Number of wellhead separators sending oil to atmospheric tanks.
    (B) Estimated average separator temperature, in degrees Fahrenheit, 
and estimated average pressure, in psig.
    (C) Estimated average sales oil stabilized API gravity, in degrees.
    (D) Count of hydrocarbon tanks at well pads.
    (E) Best estimate of count of stock tanks not at well pads 
receiving your oil.
    (F) Total volume of oil from all wellhead separators sent to 
tank(s) in barrels per year.
    (G) Count of tanks with emissions control measures, either vapor 
recovery system or flaring, for tanks at well pads.
    (H) Best estimate of count of stock tanks assumed to have emissions 
control measures not at well pads, receiving your oil.
    (I) Range of concentrations of flash gas, CH<INF>4</INF> and 
CO<INF>2</INF>.
    (J) Report emissions individually for Calculation Methodology 1 and 
2 of Sec.  98.233(j).
    (ii) For wells with oil production greater than or equal to 10 
barrels per day, using Calculation Methodology 3 and 4 of Sec.  
98.233(j), report the following by field:
    (A) Total volume of sales oil from all wells in barrels per year.
    (B) Total number of wells sending oil directly to tanks.
    (C) Total number of wells sending oil to separators off the well 
pads.
    (D) Sales oil API gravity range for (B) and (C) of this section, in 
degrees.
    (E) Count of hydrocarbon tanks on wellpads.
    (F) Count of hydrocarbon tanks, both on and off well pads assumed 
to have emissions control measures: either vapor recovery system or 
flaring of tank vapors.
    (G) Report emissions collectively for Calculation Methodology 3 and 
4 of Sec.  98.233(j).
    (iii) For wellhead gas-liquid separators and wells with throughput 
less than 10 barrels per day, using Calculation Methodology 5 of Sec.  
98.233(j) Equation W-15 of Sec.  98.233), report the following:
    (A) Number of wellhead separators.
    (B) Number of wells without wellhead separators.
    (C) Total volume of oil production in barrels per year.
    (D) Best estimate of fraction of production sent to tanks with 
assumed control measures: either vapor recovery system or flaring of 
tank vapors.
    (E) Count of hydrocarbon tanks on well pads.
    (F) Report CO<INF>2</INF> and CH<INF>4</INF> emissions 
collectively.
    (iv) If wellhead separator dump valve is functioning improperly 
during the calendar year (refer to Equation W-16 of Sec.  98.233), 
report the following:
    (A) Count of wellhead separators that dump valve factor is applied.
    (9) For transmission tank emissions identified using optical gas 
imaging instrument per Sec.  98.234(a) (refer to Sec.  98.233(k)), or 
acoustic leak detection of scrubber dump valves report the following 
for each tank:
    (i) Report emissions individually.
    (ii) [Reserved]
    (10) For well testing (refer to Equation W-17 of Sec.  98.233), 
report the following for each basin:
    (i) Number of wells tested per basin in calendar year.
    (ii) Average gas to oil ratio for each basin.
    (iii) Average number of days the well is tested in a basin.
    (iv) Report emissions of the venting gas collectively.
    (11) For associated natural gas venting (refer to Equation W-18 of 
Sec.  98.233), report the following for each basin:
    (i) Number of wells venting or flaring associated natural gas in a 
calendar year.
    (ii) Average gas to oil ratio for each basin.

[[Page 74510]]

    (iii) Report emissions of the flaring gas collectively.
    (12) For flare stacks (refer to Equation W-19, W-20, and W-21 of 
Sec.  98.233), report the following for each flare:
    (i) Whether flare has a continuous flow monitor.
    (ii) Volume of gas sent to flare in cubic feet per year.
    (iii) Percent of gas sent to un-lit flare determined by engineering 
estimate and process knowledge based on best available data and 
operating records.
    (iv) Whether flare has a continuous gas analyzer.
    (v) Flare combustion efficiency.
    (vi) Report uncombusted and combusted CO<INF>2</INF> and 
CH<INF>4</INF> emissions separately.
    (13) For each centrifugal compressor:
    (i) For compressors with wet seals in operational mode (refer to 
Equations W-22 through W-24 of Sec.  98.233), report the following for 
each degassing vent:
    (A) Number of wet seals connected to the degassing vent.
    (B) Fraction of vent gas recovered for fuel or sales or flared.
    (C) Annual throughput in million scf, use an engineering 
calculation based on best available data.
    (D) Type of meters used for making measurements.
    (E) Reporter emission factor for wet seal oil degassing vents in 
cubic feet per hour (refer to Equation W-24 of Sec.  98.233).
    (F) Total time the compressor is operating in hours.
    (G) Report seal oil degassing vent emissions for compressors 
measured (refer to Equation W-22 of Sec.  98.233) and for compressors 
not measured (refer to Equation W-23 and Equation W-24 of Sec.  
98.233).
    (ii) For wet and dry seal centrifugal compressors in operating 
mode, (refer to Equations W-22 through W-24 of Sec.  98.233), report 
the following:
    (A) Total time in hours the compressor is in operating mode.
    (B) Reporter emission factor for blowdown vents in cubic feet per 
hour (refer to Equation W-24 of Sec.  98.233).
    (C) Report blowdown vent emissions when in operating mode (refer to 
Equation W-23 and Equation W-24 of Sec.  98.233).
    (iii) For wet and dry seal centrifugal compressors in not 
operating, depressurized mode (refer to Equations W-22 through W-24 of 
Sec.  98.233), report the following:
    (A) Total time in hours the compressor is in shutdown, 
depressurized mode.
    (B) Reporter emission factor for isolation valve emissions in 
shutdown, depressurized mode in cubic feet per hour (refer to Equation 
W-24 of Sec.  98.233).
    (C) Report the isolation valve leakage emissions in not operating, 
depressurized mode in cubic feet per hour (refer to Equation W-23 and 
Equation W-24 of Sec.  98.233).
    (iv) Report total annual compressor emissions from all modes of 
operation (refer to Equation W-24 of Sec.  98.233).
    (v) For centrifugal compressors in onshore petroleum and natural 
gas production (refer to Equation W-25 of Sec.  98.233), report the 
following:
    (A) Count of compressors.
    (B) Report emissions (refer to Equation W-25 of Sec.  98.233) 
collectively.
    (14) For reciprocating compressors:
    (i) For reciprocating compressors rod packing emissions with or 
without a vent in operating mode, report the following:
    (A) Annual throughput in million scf, use an engineering 
calculation based on best available data.
    (B) Total time in hours the reciprocating compressor is in 
operating mode.
    (C) Report rod packing emissions for compressors measured (refer to 
Equation W-26 of Sec.  98.233) and for compressors not measured (refer 
to Equation W-27 and Equation W-28 of Sec.  98.233).
    (ii) For reciprocating compressors blowdown vents not manifold to 
rod packing vents, in operating and standby pressurized mode (refer to 
Equations W-26 through W-28 of Sec.  98.233), report the following:
    (A) Total time in hours the compressor is in standby, pressurized 
mode.
    (B) Reporter emission factor for blowdown vents in cubic feet per 
hour (refer to Sec.  98.233, Equation W-28).
    (C) Report blowdown vent emissions when in operating and standby 
pressurized modes (refer to Equation W-27 and Equation W-28 of Sec.  
98.233).
    (iii) For reciprocating compressors in not operating, depressurized 
mode (refer to Equations W-26 through W-28 of Sec.  98.233), report the 
following:
    (A) Total time the compressor is in not operating, depressurized 
mode.
    (B) Reporter emission factor for isolation valve emissions in not 
operating, depressurized mode in cubic feet per hour (refer to Equation 
W-28 of Sec.  98.233).
    (C) Report the isolation valve leakage emissions in not operating, 
depressurized mode.
    (iv) Report total annual compressor emissions from all modes of 
operation (refer to Equation W-27 and Equation W-28 of Sec.  98.233).
    (v) For reciprocating compressors in onshore petroleum and natural 
gas production (refer to Equation W-29 of Sec.  98.233), report the 
following:
    (A) Count of compressors.
    (B) Report emissions collectively.
    (15) For each equipment leak sources that uses emission factors for 
estimating emissions (refer to Sec.  98.233(q) and (r).
    (i) For equipment leaks found in each leak survey (refer to Sec.  
98.233(q)), report the following:
    (A) Total count of leaks found in each complete survey listed by 
date of survey and each type of leak source for which there is a leaker 
emission factor in Tables W-2, W-3, W-4, W-5, W-6, and W-7 of this 
subpart.
    (B) Concentration of CH<INF>4</INF> and CO<INF>2</INF> as described 
in Equation W-30 of Sec.  98.233.
    (C) Report CH<INF>4</INF> and CO<INF>2</INF> emissions (refer to 
Equation W-30 of Sec.  98.233) collectively by equipment type.
    (ii) For equipment leaks calculated using population counts and 
factors (refer to Sec.  98.233(r)), report the following:
    (A) For source categories Sec.  98.230(a)(3), (a)(4), (a)(5), 
(a)(6), and (a)(7), total count for each type of leak source in Tables 
W-2, W-3, W-4, W-5, and W-6 of this subpart for which there is a 
population emission factor, listed by major heading and component type.
    (B) For onshore production (refer to Sec.  98.230 paragraph 
(a)(2)), total count for each type of major equipment in Table W-1B and 
Table W-1C of this subpart, by field.
    (C) Report CH<INF>4</INF> and CO<INF>2</INF> emissions (refer to 
Equation W-31 of Sec.  98.233) collectively by equipment type.
    (16) For local distribution companies, report the following:
    (i) Number of custody transfer gate stations.
    (ii) Number of non-custody transfer gate stations.
    (iii) Custody transfer gate station meter run leak factor (refer to 
Equation W-32 of Sec.  98.233).
    (iv) Number of below grade M&R stations with inlet pressure greater 
than 300 psig.
    (v) Number of below grade M&R stations with inlet pressure between 
100 and 300 psig.
    (vi) Number of below grate M&R stations with inlet pressure less 
than 100 psig.
    (vii) Number of miles of unprotected steel distribution mains.
    (viii) Number of miles of protected steel distribution mains.
    (ix) Number of miles of plastic distribution mains.
    (x) Number of miles of cast iron distribution mains.
    (xi) Number of unprotected steel distribution services.
    (xii) Number of protected steel distribution services.

[[Page 74511]]

    (xiii) Number of plastic distribution services.
    (xiv) Number of copper distribution services.
    (xv) Total emissions from each natural gas distribution facility.
    (17) For each EOR injection pump blowdown (refer to Equation W-37 
of Sec.  98.233), report the following:
    (i) Pump capacity, in barrels per day.
    (ii) Volume of critical phase gas between isolation valves.
    (iii) Number of blowdowns per year.
    (iv) Critical phase EOR injection gas density.
    (v) Report emissions collectively.
    (18) For EOR hydrocarbon liquids dissolved CO<INF>2</INF> for each 
field (refer to Equation W-38 of Sec.  98.233), report the following:
    (i) Volume of crude oil produced in barrels per year.
    (ii) Amount of CO<INF>2</INF> retained in hydrocarbon liquids in 
metric tons per barrel, under standard conditions.
    (iii) Report emissions individually.
    (19) For onshore petroleum and natural gas production and natural 
gas distribution combustion emissions, report the following:
    (i) Cumulative number of external fuel combustion units with a 
rated heat capacity equal to or less than 5 mmBtu/hr, by type of unit.
    (ii) Cumulative number of external fuel combustion units with a 
rated heat capacity larger than 5 mmBtu/hr, by type of unit.
    (iii) Cumulative emissions from external fuel combustion units with 
a rated heat capacity larger than 5 mmBtu/hr, by type of unit.
    (iv) Cumulative volume of fuel combusted in external fuel 
combustion units with a rated heat capacity larger than 5 mmBtu/hr, by 
fuel type.
    (v) Cumulative number of all internal combustion units, by type of 
unit.
    (vi) Cumulative emissions from internal combustion units, by type 
of unit.
    (vii) Cumulative volume of fuel combusted in internal combustion 
units, by fuel type.
    (d) Report annual throughput as determined by engineering estimate 
based on best available data for each industry segment listed in 
paragraphs (a)(1) through (a)(8) of this section.


Sec.  98.237  Records that must be retained.

    Monitoring Plans, as described in Sec.  98.3(g)(5), must be 
completed by April 1, 2011. 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 in this section, all terms used in this subpart 
have the same meaning given in the Clean Air Act and subpart A of this 
part.
    Acid gas means hydrogen sulfide (H<INF>2</INF>S) and/or carbon 
dioxide (CO<INF>2</INF>) contaminants that are separated from sour 
natural gas by an acid gas removal unit.
    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 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.
    Basin means geologic provinces as defined by the American 
Association of Petroleum Geologists (AAPG) Geologic Note: AAPG-CSD 
Geologic Provinces Code Map: AAPG Bulletin, Prepared by Richard F. 
Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 
(October 1991) (incorporated by reference, see Sec.  98.7) and the 
Alaska Geological Province Boundary Map, Compiled by the American 
Association of Petroleum Geologists Committee on Statistics of Drilling 
in Cooperation with the USGS, 1978 (incorporated by reference, see 
Sec.  98.7).
    Component means 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 or CO<INF>2</INF> by drawing in low pressure natural gas or 
CO<INF>2</INF> and discharging significantly higher pressure natural 
gas or CO<INF>2.</INF>
    Condensate means hydrocarbon and other liquid, including both water 
and hydrocarbon liquids, separated from natural gas that condenses due 
to changes in the temperature, pressure, or both, and remains liquid at 
storage conditions.
    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 subpart, 
EOR applies to injection of critical phase or immiscible carbon dioxide 
into a crude oil reservoir to enhance the recovery of oil.
    Equipment leak means those emissions which could not reasonably 
pass through a stack, chimney, vent, or other functionally-equivalent 
opening.
    Equipment leak detection means the process of identifying emissions 
from equipment, components, and other point sources.
    External combustion means fired combustion in which the flame and 
products of combustion are separated from contact with the process 
fluid to which the energy is delivered. Process fluids may be air, hot 
water, or hydrocarbons. External combustion equipment may include fired 
heaters, industrial boilers, and commercial and domestic combustion 
units.
    Facility with respect to natural gas distribution for purposes of 
this subpart and for subpart A means the collection of all 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.
    Facility with respect to onshore petroleum and natural gas 
production for purposes of this subpart and for subpart A means all 
petroleum or natural gas equipment on a well pad or associated with a 
well pad and CO<INF>2</INF> EOR operations that are under common 
ownership or common control including leased, rented, or contracted 
activities by an onshore petroleum and natural gas production owner or 
operator and that are located in a single hydrocarbon basin as defined 
in Sec.  98.238. Where a person or entity owns or operates more than 
one well in a basin, then all onshore petroleum and natural gas 
production equipment associated with all wells that the person or 
entity owns or operates in the basin would be considered one facility.
    Farm Taps are pressure regulation stations that deliver gas 
directly from transmission pipelines to generally rural customers. The 
gas may or may not be metered, but always does not pass through a city 
gate station. In some cases a nearby LDC may handle the billing of the 
gas to the customer(s).

[[Page 74512]]

    Field means oil and gas fields identified in the United States as 
defined by the Energy Information Administration Oil and Gas Field Code 
Master List 2008, DOE/EIA 0370(08) (incorporated by reference, see 
Sec.  98.7).
    Flare stack emissions means CO<INF>2</INF> and N<INF>2</INF>O from 
partial combustion of hydrocarbon gas sent to a flare plus 
CH<INF>4</INF> emissions resulting from the incomplete combustion of 
hydrocarbon gas in flares.
    Flare combustion efficiency means the fraction of hydrocarbon gas, 
on a volume or mole basis, that is combusted at the flare burner tip.
    Gas well means a well completed for production of natural gas from 
one or more gas zones or reservoirs. Such wells contain no completions 
for the production of crude oil.
    Internal combustion means the combustion of a fuel that occurs with 
an oxidizer (usually air) in a combustion chamber. In an internal 
combustion engine the expansion of the high-temperature and -pressure 
gases produced by combustion applies direct force to a component of the 
engine, such as pistons, turbine blades, or a nozzle. This force moves 
the component over a distance, generating useful mechanical energy. 
Internal combustion equipment may include gasoline and diesel 
industrial engines, natural gas-fired reciprocating engines, and gas 
turbines.
    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 boil-off 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.
    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.
    Oil well means a well completed for the production of crude oil 
from at least one oil zone or reservoir.
    Onshore petroleum and natural gas production owner or operator 
means the person or entity who holds the permit to operate petroleum 
and natural gas wells on the drilling permit or an operating permit 
where no drilling permit is issued, which operates an onshore petroleum 
and/or natural gas production facility (as described in Sec.  
98.230(a)(2). Where petroleum and natural gas wells operate without a 
drilling or operating permit, the person or entity that pays the State 
or Federal business income taxes is considered the owner or operator.
    Operating pressure means the containment pressure that 
characterizes the normal state of gas or liquid inside a particular 
process, pipeline, vessel or tank.
    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.
    Reservoir means a porous and permeable underground natural 
formation containing significant quantities of hydrocarbon liquids and/
or gases.
    Residue Gas and Residue Gas Compression mean, respectively, 
production lease natural gas from which gas liquid products and, in 
some cases, non-hydrocarbon components have been extracted such that it 
meets the specifications set by a pipeline transmission company, and/or 
a distribution company; and the compressors operated by the processing 
facility, whether inside the processing facility boundary fence or 
outside the fence-line, that deliver the residue gas from the 
processing facility to a transmission pipeline.
    Separator means a vessel in which streams of multiple phases are 
gravity separated into individual streams of single phase.
    Transmission pipeline means high pressure cross country pipeline 
transporting saleable 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.
    Vented emissions means intentional or designed releases of 
CH<INF>4</INF> or CO<INF>2</INF> containing natural gas or hydrocarbon 
gas (not including stationary combustion flue gas), including 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).

 Table W-1A to Subpart W of Part 98--Default Whole Gas Emission Factors
            for Onshore Petroleum and Natural Gas Production
------------------------------------------------------------------------
                                                             Emission
                                                           factor (scf/
      Onshore petroleum and natural gas production             hour/
                                                            component)
------------------------------------------------------------------------
                              Eastern U.S.
------------------------------------------------------------------------
Population Emission Factors--All Components, Gas
 Service:\1\
Valve...................................................           0.027
Connector...............................................           0.004
Open-ended Line.........................................           0.062
Pressure Relief Valve...................................           0.041
Low Continuous Bleed Pneumatic Device Vents \2\.........            1.80
High Continuous Bleed Pneumatic Device Vents \2\........            48.1
Intermittent Bleed Pneumatic Device Vents \2\...........            17.4
Pneumatic Pumps \3\.....................................            13.3
Population Emission Factors--All Components, Light Crude
 Service:\4\
Valve...................................................            0.04
Flange..................................................           0.002
Connector...............................................           0.005
Open-ended Line.........................................            0.04
Pump....................................................            0.01
Other \5\...............................................            0.23
Population Emission Factors--All Components, Heavy Crude
 Service:\6\
Valve...................................................          0.0004
Flange..................................................          0.0007
Connector (other).......................................          0.0002
Open-ended Line.........................................           0.004
Other \5\...............................................           0.002
------------------------------------------------------------------------
                              Western U.S.
------------------------------------------------------------------------
Population Emission Factors--All Components, Gas
 Service:\1\
Valve...................................................           0.123
Connector...............................................           0.017
Open-ended Line.........................................           0.032
Pressure Relief Valve...................................           0.196
Low Continuous Bleed Pneumatic Device Vents \2\.........            1.80
High Continuous Bleed Pneumatic Device Vents \2\........            48.1
Intermittent Bleed Pneumatic Device Vents \2\...........            17.4
Pneumatic Pumps \3\.....................................            13.3
Population Emission Factors--All Components, Light Crude
 Service:\4\
Valve...................................................            0.04
Flange..................................................           0.002
Connector (other).......................................           0.005
Open-ended Line.........................................            0.04
Pump....................................................            0.01
Other \5\...............................................            0.23

[[Page 74513]]

 
Population Emission Factors--All Components, Heavy Crude
 Service:\6\
Valve...................................................          0.0004
Flange..................................................          0.0007
Connector (other).......................................          0.0002
Open-ended Line.........................................           0.004
Other \5\...............................................          0.002
------------------------------------------------------------------------
\1\ For multi-phase flow that includes gas, use the gas service
  emissions factors.
\2\ Emission Factor is in units of ``scf/hour/device.''
\3\ Emission Factor is in units of ``scf/hour/pump.''
\4\ Hydrocarbon liquids greater than or equal to 20[deg]API are
  considered ``light crude.''.
\5\ ''Others'' category includes instruments, loading arms, pressure
  relief valves, stuffing boxes, compressor seals, dump lever arms, and
  vents.
\6\ Hydrocarbon liquids less than 20[deg]API are considered ``heavy
  crude.''


  Table W-1B to Subpart W of Part 98--Default Average Component Counts for Major Onshore Natural Gas Production
                                                    Equipment
----------------------------------------------------------------------------------------------------------------
                                                                                    Open-ended       Pressure
                 Major equipment                      Valves        Connectors         lines       relief valves
----------------------------------------------------------------------------------------------------------------
                                                  Eastern U.S.
----------------------------------------------------------------------------------------------------------------
Wellheads.......................................               8              38             0.5               0
Separators......................................               1               6               0               0
Meters/piping...................................              12              45               0               0
Compressors.....................................              12              57               0               0
In-line heaters.................................              14              65               2               1
Dehydrators.....................................              24              90               2               2
----------------------------------------------------------------------------------------------------------------
                                                  Western U.S.
----------------------------------------------------------------------------------------------------------------
Wellheads.......................................              11              36               1               0
Separators......................................              34             106               6               2
Meters/piping...................................              14              51               1               1
Compressors.....................................              73             179               3               4
In-line heaters.................................              14              65               2               1
Dehydrators.....................................              24              90               2               2
----------------------------------------------------------------------------------------------------------------


  Table W-1C to Subpart W of Part 98--Default Average Component Counts For Major Crude Oil Production Equipment
----------------------------------------------------------------------------------------------------------------
                                                                                    Open-ended         Other
         Major equipment              Valves          Flanges       Connectors         lines        components
----------------------------------------------------------------------------------------------------------------
                                                  Eastern U.S.
----------------------------------------------------------------------------------------------------------------
Wellhead........................               5              10               4               0               1
Separator.......................               6              12              10               0               0
Heater-treater..................               8              12              20               0               0
Header..........................               5              10               4               0               0
----------------------------------------------------------------------------------------------------------------
                                                  Western U.S.
----------------------------------------------------------------------------------------------------------------
Wellhead........................               5              10               4               0               1
Separator.......................               6              12              10               0               0
Heater-treater..................               8              12              20               0               0
Header..........................               5              10               4               0               0
----------------------------------------------------------------------------------------------------------------


 Table W-1D of Subpart W of Part 98--Designation Of Eastern And Western
                                  U.S.
------------------------------------------------------------------------
               Eastern U.S.                         Western U.S.
------------------------------------------------------------------------
Connecticut...............................  Alabama
Delaware..................................  Alaska
Florida...................................  Arizona
Georgia...................................  Arkansas
Illinois..................................  California
Indiana...................................  Colorado
Kentucky..................................  Hawaii
Maine.....................................  Idaho
Maryland..................................  Iowa
Massachusetts.............................  Kansas
Michigan..................................  Louisiana
New Hampshire.............................  Minnesota
New Jersey................................  Mississippi
New York..................................  Missouri
North Carolina............................  Montana

[[Page 74514]]

 
Ohio......................................  Nebraska
Pennsylvania..............................  Nevada
Rhode Island..............................  New Mexico
South Carolina............................  North Dakota
Tennessee.................................  Oklahoma
Vermont...................................  Oregon
Virginia..................................  South Dakota
West Virginia.............................  Texas
Wisconsin.................................  Utah
                                            Washington
                                            Wyoming
------------------------------------------------------------------------


  Table W-2 to Subpart W of Part 98--Default Total Hydrocarbon Emission
               Factors for Onshore Natural Gas Processing
------------------------------------------------------------------------
                                                             Emission
                                                           Factor (scf/
             Onshore natural gas processing                    hour/
                                                            component)
------------------------------------------------------------------------
       Leaker Emission Factors--Compressor Components, Gas Service
------------------------------------------------------------------------
Valve\1\................................................           15.07
Connector...............................................            5.68
Open-Ended Line.........................................           17.54
Pressure Relief Valve...................................           40.27
Meter...................................................           19.63
------------------------------------------------------------------------
     Leaker Emission Factors--Non-Compressor Components, Gas Service
------------------------------------------------------------------------
Valve...................................................            6.52
Connector...............................................            5.80
Open-Ended Line.........................................           11.44
Pressure Relief Valve...................................            2.04
Meter...................................................            2.98
------------------------------------------------------------------------
\1\ Valves include control valves, block valves and regulator valves.


  Table W-3 to Subpart W of Part 98--Default Total Hydrocarbon Emission
        Factors for Onshore Natural Gas Transmission Compression
------------------------------------------------------------------------
                                                             Emission
                                                           Factor (scf/
      Onshore natural gas transmission compression             hour/
                                                            component)
------------------------------------------------------------------------
       Leaker Emission Factors--Compressor Components, Gas Service
------------------------------------------------------------------------
Valve\1\................................................           15.07
Connector...............................................            5.68
Open-Ended Line.........................................           17.54
Pressure Relief Valve...................................           40.27
Meter...................................................           19.63
------------------------------------------------------------------------
     Leaker Emission Factors--Non-Compressor Components, Gas Service
------------------------------------------------------------------------
Valve\1\................................................            6.52
Connector...............................................            5.80
Open-Ended Line.........................................           11.44
Pressure Relief Valve...................................            2.04
Meter...................................................            2.98
------------------------------------------------------------------------
                Population Emission Factors--Gas Service
------------------------------------------------------------------------
Low Continuous Bleed Pneumatic Device Vents\2\..........            1.41
High Continuous Bleed Pneumatic Device Vents\2\.........            18.8
Intermittent Bleed Pneumatic Device Vents\2\............            18.8
------------------------------------------------------------------------
\1\ Valves include control valves, block valves and regulator valves.
\2\ Emission Factor is in units of ``scf/hour/device.''


  Table W-4 to Subpart W of Part 98--Default Total Hydrocarbon Emission
               Factors for Underground Natural Gas Storage
------------------------------------------------------------------------
                                                             Emission
                                                           Factor (scf/
             Underground natural gas storage                   hour/
                                                            component)
------------------------------------------------------------------------
Leaker Emission Factors--Storage Station, Gas Service...................
------------------------------------------------------------------------
Valve \1\...............................................           15.07
Connector...............................................            5.68
Open-Ended Line.........................................           17.54
Pressure Relief Valve...................................           40.27
Meter...................................................           19.63
------------------------------------------------------------------------
       Population Emission Factors--Storage Wellheads, Gas Service
------------------------------------------------------------------------
Connector...............................................            0.01
------------------------------------------------------------------------
Valve...................................................            0.10
Pressure Relief Valve...................................            0.17
------------------------------------------------------------------------
Leaker Emission Factors--Storage Station, Gas Service...................
------------------------------------------------------------------------
Open-ended Line.........................................            0.03
------------------------------------------------------------------------
Population Emission Factors--Other Components, Gas Service..............
------------------------------------------------------------------------
Low Continuous Bleed Pneumatic Device Vents \2\.........            1.41
High Continuous Bleed Pneumatic Device Vents \2\........            18.8
Intermittent Bleed Pneumatic Device Vents \2\...........            18.8
------------------------------------------------------------------------
\1\ Valves include control valves, block valves and regulator valves.
\2\ Emission Factor is in units of ``scf/hour/device''


 Table W-5 to Subpart W of Part 98--Default Methane Emission Factors for
                   Liquefied Natural Gas (LNG) Storage
------------------------------------------------------------------------
                                                             Emission
                                                           Factor (scf/
                       LNG Storage                             hour/
                                                            component)
------------------------------------------------------------------------
Leaker Emission Factors--LNG Storage Components, LNG Service............
------------------------------------------------------------------------
Valve...................................................            1.21
Pump Seal...............................................            4.06
Connector...............................................            0.35
Other \1\...............................................            1.80
------------------------------------------------------------------------
Population Emission Factors--LNG Storage Compressor, Gas Service........
------------------------------------------------------------------------
Vapor Recovery Compressor\2\............................            4.23
------------------------------------------------------------------------
\1\ ``other'' equipment type should be applied for any equipment type
  other than connectors, pumps, or valves.
\2\ Emission Factor is in units of ``scf/hour/compressor.''


 Table W-6 to Subpart W of Part 98--Default Methane Emission Factors for
                     LNG Import and Export Equipment
------------------------------------------------------------------------
                                                             Emission
                                                           Factor (scf/
             LNG import and export equipment                   hour/
                                                            component)
------------------------------------------------------------------------
Leaker Emission Factors--LNG Terminals Components, LNG Service..........
------------------------------------------------------------------------
Valve...................................................            1.21
Pump Seal...............................................            4.06
Connector...............................................            0.35
Other \1\...............................................            1.80
------------------------------------------------------------------------
Population Emission Factors--LNG Terminals Compressor, Gas Service......
------------------------------------------------------------------------
Vapor Recovery Compressor \2\...........................            4.23
------------------------------------------------------------------------
\1\ ``other'' equipment type should be applied for any equipment type
  other than connectors, pumps, or valves.
\2\ Emission Factor is in units of ``scf/hour/compressor.''


 Table W-7 to Subpart W of Part 98--Default Methane Emission Factors for
                        Natural Gas Distribution
------------------------------------------------------------------------
                                                             Emission
                                                           Factor (scf/
                Natural gas distribution                       hour/
                                                            component)
------------------------------------------------------------------------
Leaker Emission Factors--Above Grade M&R at City Gate Stations \1\
 Components, Gas Service................................................
------------------------------------------------------------------------
Connector...............................................            1.72
Block Valve.............................................           0.566
Control Valve...........................................            9.48
Pressure Relief Valve...................................           0.274
Orifice Meter...........................................           0.215

[[Page 74515]]

 
Regulator...............................................           0.784
Open-ended Line.........................................          26.533
------------------------------------------------------------------------
Population Emission Factors--Below Grade M&R \2\ Components, Gas Service
 \3\....................................................................
------------------------------------------------------------------------
Below Grade M&R Station, Inlet Pressure > 300 psig......            1.32
Below Grade M&R Station, Inlet Pressure 100 to 300 psig.            0.20
Below Grade M&R Station, Inlet Pressure < 100 psig......            0.10
------------------------------------------------------------------------
Population Emission Factors--Distribution Mains, Gas Service \4\........
------------------------------------------------------------------------
Unprotected Steel.......................................           12.77
Protected Steel.........................................            0.36
Plastic.................................................            1.15
Cast Iron...............................................           27.67
------------------------------------------------------------------------
Population Emission Factors--Distribution Services, Gas Service \5\.....
------------------------------------------------------------------------
Unprotected Steel.......................................            0.19
Protected Steel.........................................            0.02
Plastic.................................................           0.001
Copper..................................................            0.03
------------------------------------------------------------------------
\1\ City gate stations at custody transfer and excluding customer
  meters.
\2\ Excluding customer meters.
\3\ Emission Factor is in units of ``scf/hour/station''.
\4\ Emission Factor is in units of ``scf/hour/mile''.
\5\ Emission Factor is in units of ``scf/hour/number of services''.

[FR Doc. 2010-28655 Filed 11-29-10; 8:45 am]
BILLING CODE 6560-50-P


</pre><script data-cfasync="false" src="/cdn-cgi/scripts/5c5dd728/cloudflare-static/email-decode.min.js"></script></body>
</html>