Monday, 

April 12, 2010 

Part III 

Environmental 

Protection Agency 

40 CFR Part 98 

Mandatory Reporting of Greenhouse 

Gases: Petroleum and Natural Gas 

Systems; Proposed Rule 


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18608 Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 98 

[EPA–HQ–OAR–2009–0923; FRL–9131–1] 

RIN 2060–AP99 

Mandatory Reporting of Greenhouse 

Gases: Petroleum and Natural Gas 

Systems 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: EPA is proposing a 

supplemental rule to require reporting 

of greenhouse gas (GHG) emissions from 

petroleum and natural gas systems. 

Specifically, the proposed supplemental 

rulemaking would require emissions 

reporting from the following industry 

segments: Onshore petroleum and 

natural gas production, offshore 

petroleum and natural gas production, 

natural gas processing, natural gas 

transmission compressor stations, 

underground natural gas storage, 

liquefied natural gas (LNG) storage, LNG 

import and export terminals, and 

distribution. The proposed 

supplemental rulemaking does not 

require control of GHGs, rather it 

requires only that sources above certain 

threshold levels monitor and report 

emissions. 

DATES: Comments must be received on 

or before June 11, 2010. There will be 

one public hearing. The hearing will be 

on April 19, 2010 in Arlington, VA and 

will begin at 8 a.m. local time and end 

at 5 p.m. local time. 

ADDRESSES: You may submit your 

comments, identified by docket EPA– 

HQ–OAR–2009–0923 and/or RIN 

number 2060–AP99 by any of the 

following methods: 

• Federal eRulemaking Portal: http:// 

www.regulations.gov. Follow the online 

instructions for submitting comments. 

• E-mail: GHG_Reporting_Rule_Oil_

and_Natural_Gas@epa.gov. Include 

EPA–HQ–OAR–2009–0923 and/or RIN 

number 2060–AP99 in the subject line 

of the message. 

• Fax: (202) 566–1741. 

• Phone: (202) 566–1744. 

• Mail: Environmental Protection 

Agency, EPA Docket Center (EPA/DC), 

Attention Docket EPA–HQ–OAR–2009– 

0923, Mail Code 2822T, 1200 

Pennsylvania Avenue, NW., 

Washington, DC 20460. 

• Hand/Courier Delivery: EPA Docket 

Center Public Reading Room, Room 

3334, EPA West Building, Attention 

Docket EPA–HQ–OAR–2009–0923, 1301 

Constitution Avenue, NW., Washington, 

DC 20004. Such deliveries are only 

accepted during the Docket’s normal 

hours of operation, and special 

arrangements should be made for 

deliveries of boxed information. 

Instructions: Direct your comments to 

Docket ID No. EPA–HQ–OAR–2009– 

0923. EPA’s policy is that all comments 

received will be included in the public 

docket without change and may be 

made available online at http:// 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be CBI or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through http:// 

www.regulations.gov or e-mail. The 

http://www.regulations.gov Web site is 

an ‘‘anonymous access’’ system, which 

means EPA will not know your identity 

or contact information unless you 

provide it in the body of your comment. 

If you send an e-mail comment directly 

to EPA without going through http:// 

www.regulations.gov your e-mail 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, EPA may not be 

able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. 

Docket: All documents in the docket 

are listed in the http:// 

www.regulations.gov index. Although 

listed in the index, some information is 

not publicly available, e.g., CBI or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

will be publicly available only in hard 

copy. Publicly available docket 

materials are available either 

electronically in http:// 

www.regulations.gov or in hard copy at 

the Air Docket, EPA’s Docket Center, 

Public Reading Room, EPA West 

Building, Room 3334, 1301 Constitution 

Ave., NW., Washington, DC 20004. This 

Docket Facility is open from 8:30 a.m. 

to 4:30 p.m., Monday through Friday, 

excluding legal holidays. The telephone 

number for the Public Reading Room is 

(202) 566–1744, and the telephone 

number for the Air Docket is (202) 566– 

1742. 

FOR FURTHER GENERAL INFORMATION

CONTACT: Carole Cook, Climate Change 

Division, Office of Atmospheric 

Programs (MC–6207J), Environmental 

Protection Agency, 1200 Pennsylvania 

Ave., NW., Washington, DC 20460; 

telephone number: (202) 343–9263; fax 

number: (202) 343–2342; e-mail address: 

GHGMRR@epa.gov. For technical 

information contact the Greenhouse Gas 

Reporting Rule Hotline at telephone 

number: (877) 444–1188; or e-mail: 

GHGMRR@epa.gov. To obtain 

information about the public hearings or 

to register to speak at the hearings, 

please go to http://www.epa.gov/ 

climatechange/emissions/ 

ghgrulemaking.html. Alternatively, 

contact Carole Cook at 202–343–9263. 

SUPPLEMENTARY INFORMATION: EPA first 

proposed Mandatory GHG Reporting 

requirements for petroleum and natural 

gas systems (under 40 CFR, part 98, 

subpart W) in April 2009. EPA received 

a substantial number of comments on 

this initial proposal for petroleum and 

natural gas systems. For this reason, 

EPA decided not to finalize the rule for 

petroleum and natural gas systems, and 

instead to propose a supplemental rule. 

EPA reviewed and considered 

comments submitted on the previous 

proposal in drafting this proposed 

supplemental rulemaking. However, as 

this is a new proposal, EPA is not here 

responding to comments on the earlier 

version of this rule. Any comments 

must be submitted as provided herein, 

to be considered. A more detailed 

background concerning the subpart W 

rulemaking and proposed changes can 

be found in section II–A. 

Additional Information on Submitting 

Comments: To expedite review of your 

comments by Agency staff, you are 

encouraged to send a separate copy of 

your comments, in addition to the copy 

you submit to the official docket, to 

Carole Cook, U.S. EPA, Office of 

Atmospheric Programs, Climate Change 

Division, Mail Code 6207–J, 1200 

Pennsylvania Ave., NW., Washington, 

DC 20460, telephone (202) 343–9263, email: GHG_Reporting_Rule_Oil_and

_Natural_Gas@epa.gov. 

Although as indicated above, EPA 

previously proposed a version of this 

rule, that proposal never became final. 

This is a newly proposed rule and 

comments which were submitted on the 

earlier version of the rule are not being 

considered in the context of this rule. 

Any parties interested in commenting 

must do so at this time. 

Regulated Entities. The Administrator 

determined that this action is subject to 

the provisions of Clean Air Act (CAA) 

section 307(d). See CAA section 


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307(d)(1)(V) (the provisions of section 

307(d) apply to ‘‘such other actions as 

the Administrator may determine.’’). 

This is a proposed regulation. If 

finalized, these regulations would affect 

owners or operators of petroleum and 

natural gas systems. Regulated 

categories and entities include those 

listed in Table 1 of this preamble: 

TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY

Source Category NAICS Examples of affected facilities 

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

221210 Natural gas distribution facilities. 

211 Extractors of crude petroleum and natural gas. 

211112 Natural gas liquid extraction facilities. 

Table 1 of this preamble is not 

intended to be exhaustive, but rather 

provides a guide for readers regarding 

facilities likely to be affected by this 

action. Table 1 of this preamble lists the 

types of facilities that EPA is now aware 

could be potentially affected by the 

reporting requirements. Other types of 

facilities listed in the table could also be 

subject to reporting requirements. To 

determine whether you are affected by 

this action, you should carefully 

examine the applicability criteria found 

in proposed 40 CFR part 98, subpart A 

or the relevant criteria in the sections 

related to petroleum and natural gas 

systems. If you have questions regarding 

the applicability of this action to a 

particular facility, consult the person 

listed in the preceding FOR FURTHER

INFORMATION CONTACT section. 

Many facilities that are affected by the 

proposed supplemental rule have GHG 

emissions from multiple source 

categories listed in Table 1 of this 

preamble. Table 2 of this preamble has 

been developed as a guide to help 

potential reporters in the petroleum and 

natural gas industry subject to the 

proposed rule identify the source 

categories (by subpart) that they may 

need to (1) consider in their facility 

applicability determination, and/or (2) 

include in their reporting. The table 

should only be seen as a guide. 

Additional subparts in 40 CFR part 98 

may be relevant for a given reporter. 

Similarly, not all listed subparts are 

relevant for all reporters. 

TABLE 2—SOURCE CATEGORIES AND RELEVANT SUBPARTS

Source category Other Subparts recommended for review to determine 

applicability 

Petroleum and Natural Gas Systems .................................................................. 40 CFR part 98, subpart C. 

40 CFR part 98, subpart Y. 

40 CFR part 98, subpart MM. 

40 CFR part 98, subpart NN. 

40 CFR part 98, subpart PP. 

40 CFR part 98, subpart RR (proposed). 

Acronyms and Abbreviations. The 

following acronyms and abbreviations 

are used in this document. 

ASTM American Society for Testing and 

Materials 

CAA Clean Air Act 

CBI confidential business information 

cf cubic feet 

CFR Code of Federal Regulations 

CH4 methane 

CO2 carbon dioxide 

CO2e CO2-equivalent 

EO Executive Order 

EOR enhanced oil recovery 

EPA U.S. Environmental Protection Agency 

GHG greenhouse gas 

GWP global warming potential 

ICR information collection request 

IPCC Intergovernmental Panel on Climate 

Change 

kg kilograms 

LDCs local natural gas distribution 

companies 

LNG liquefied natural gas 

LPG liquefied petroleum gas 

MRR mandatory GHG reporting rule 

MMTCO2e million metric tons carbon 

dioxide equivalent 

N2O nitrous oxide 

NAICS North American Industry 

Classification System 

NGLs natural gas liquids 

OMB Office of Management and Budget 

QA quality assurance 

QA/QC quality assurance/quality control 

RFA Regulatory Flexibility Act 

RGGI Regional Greenhouse Gas Initiative 

SSM startup, shutdown, and malfunction 

TCR The Climate Registry 

TSD technical support document 

U.S. United States 

UMRA Unfunded Mandates Reform Act of 

1995 

VOC volatile organic compound(s) 

WCI Western Climate Initiative 

Table of Contents 

I. Background 

A. Organization of this Preamble 

B. Background on the Proposed Rule 

C. Legal Authority 

D. Relationship to Other Federal, State and 

Regional Programs 

II. Rationale for the Reporting, Recordkeeping 

and Verification Requirements 

A. Overview of Proposal 

B. Summary of the Major Changes Since 

Initial Proposal 

C. Definition of the Source Category 

D. Selection of Reporting Threshold 

E. Selection of Proposed Monitoring 

Methods 

F. Selection of Procedures for Estimating 

Missing Data 

G. Selection of Data Reporting 

Requirements 

H. Selection of Records That Must Be 

Retained 

III. Economic Impacts of the Proposed Rule 

A. How were compliance costs estimated? 

B. What are the costs of the proposed rule? 

C. What are the economic impacts of the 

proposed rule? 

D. What are the impacts of the proposed 

rule on small businesses? 

E. What are the benefits of the proposed 

rule for society? 

IV. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act 

(UMRA) 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 


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1Consolidated Appropriations Act, 2008, Public 

Law 110–161, 121 Stat. 1844, 2128. 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

I. Background 

A. Organization of This Preamble 

This preamble is broken into several 

large sections, as detailed above in the 

Table of Contents. The paragraphs 

below describe the layout of the 

preamble and provide a brief summary 

of each section. 

The first section of this preamble 

contains the basic background 

information about the origin of this 

proposed supplemental rulemaking, 

including a discussion of the initial 

proposed rule for petroleum and natural 

gas systems. This section also discusses 

EPA’s use of our legal authority under 

the Clean Air Act to collect the 

proposed data, and the benefits of 

collecting the data. The relationship 

between the mandatory GHG reporting 

program and other mandatory and 

voluntary reporting programs at the 

national, regional and State level also is 

discussed. 

The second section of this preamble 

summarizes the general provisions of 

this proposed supplemental rulemaking 

for petroleum and natural gas systems. 

It also highlights the major changes 

between the initial proposed rule and 

the supplemental rule that we are 

proposing today, including changes in 

the scope of the proposed rule and the 

monitoring methods proposed. This 

section then provides a brief summary 

of, and rationale for, selection of key 

design elements. Specifically, this 

section describes EPA’s rationale for (i) 

the definition of the source category (ii) 

selection of reporting thresholds (iii) 

selection of monitoring methods, (iv) 

missing data procedures (v) proposed 

data reporting requirements, and (vi) 

recordkeeping requirements. Thus, for 

example, there is a specific discussion 

regarding appropriate thresholds, 

monitoring methodologies and reporting 

and recordkeeping requirements for 

each segment of the petroleum and 

natural gas industry proposed for 

inclusion in the rule: onshore petroleum 

and natural gas production, offshore 

petroleum and natural gas production, 

natural gas processing, natural gas 

transmission compressor stations, 

natural gas underground storage, LNG 

storage, LNG import and export 

terminals, and distribution. EPA 

describes the proposed options for each 

design element, as well as the other 

options considered. Throughout this 

discussion, EPA highlights specific 

issues on which we solicit comment. 

Please refer to the specific source 

category of interest for more details. 

The third section provides the 

summary of the cost impacts, economic 

impacts, and benefits of this proposed 

rule from the Economic Analysis. 

Finally, the last section discusses the 

various statutory and executive order 

requirements applicable to this 

proposed rulemaking. 

B. Background on the Proposed Rule 

The Final Mandatory GHG Reporting 

Rule (‘‘Final MRR’’), (40 CFR part 98) 

was signed by EPA Administrator Lisa 

Jackson on September 22, 2009 and 

published in the Federal Register on 

October 30, 2009 (74 FR 209 (October 

30, 2009) pp. 56260–56519). The Final 

MRR which is effective on December 29, 

2009 included reporting of GHGs from 

facilities and suppliers that EPA 

determined met the criteria in the 2008 

Consolidated Appropriations Act.1

These source categories capture 

approximately 85 percent of U.S. GHG 

emissions through reporting by direct 

emitters as well as suppliers of fossil 

fuels and industrial gases. There are, 

however, many additional types of data 

and reporting that the Agency deems 

important and necessary to address an 

issue as large and complex as climate 

change (e.g. indirect emissions from 

electricity use). In that sense, one could 

view the Final MRR (40 CFR part 98) as 

focused on certain sources of emissions 

and upstream suppliers. For information 

on existing programs at the Federal, 

Regional and State levels that also 

collect valuable information to inform 

and implement policies necessary to 

address climate change, relationship of 

the Final MRR to EPA and U.S. 

government climate change efforts and 

to other State and Regional Programs, 

see the Preamble to the Final MRR. 

In the April 2009 proposed mandatory 

GHG reporting rule the petroleum and 

natural gas systems subcategory was 

included as Subpart W. EPA received a 

number of lengthy, detailed comments 

regarding this subpart W proposal. 

Some comments were focused on the 

significant cost burden that the April 

2009 proposed rule would impose on 

petroleum and natural gas systems, 

whereas others focused on whether 

certain sources, such as onshore 

production and distribution, that were 

not included in the initial proposal, 

should be included. EPA recognized the 

concerns raised by stakeholders, and 

decided not to finalize subpart W with 

the Final MRR, but instead to propose 

a new supplemental rule for petroleum 

and natural gas systems. This proposed 

supplemental rule incorporates a 

number of changes including, but not 

limited to, different methodologies that 

provide improved emissions coverage at 

a lower cost burden to facilities than 

would have been covered under the 

initial proposed rule; the inclusion of 

onshore production and distribution 

facilities; and separate definitions for 

‘‘vented’’ and ‘‘fugitive’’ emissions. As 

noted earlier, stakeholders should 

submit comments in the context of this 

new proposed supplemental rule. 

This proposed supplemental rule 40 

CFR part 98, subpart W requires annual 

reporting of fugitive and vented carbon 

dioxide (CO2) and methane (CH4) 

emissions from petroleum and natural 

gas systems facilities, as well as 

combustion-related CO2, CH4, and 

nitrous oxide (N2O) emissions from 

flares at those facilities, following the 

methods outlined in the proposal. This 

proposed rule would also establish 

appropriate thresholds and frequency 

for reporting, as well as provisions to 

ensure the accuracy of emissions 

through monitoring, reporting and 

recordkeeping requirements. 

This proposed rule applies to 

facilities in specific segments of the 

petroleum and natural gas industry that 

emit GHGs greater than or equal to 

25,000 metric tons of CO2 equivalent per 

year. Reporting would be at the facility 

level. 

C. Legal Authority 

EPA is proposing this rule under its 

existing CAA authority, specifically 

authorities provided in section 114 of 

the CAA. As discussed further below 

and in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Legal Issues’’ (EPA– 

HQ–OAR–2008–0508–2264), EPA is not 

citing the FY 2008 Consolidated 

Appropriations Act as the statutory 

basis for this action. While that law 

required that EPA spend no less than 

$3.5 million on a rule requiring the 

mandatory reporting of GHG emissions, 

it is the CAA, not the Appropriations 

Act, that EPA is citing as the authority 

to gather the information proposed by 

this rule. 

As stated in the Final MRR, CAA 

section 114 provides EPA broad 

authority to require the information 

proposed to be gathered by this rule 

because such data would inform and are 

relevant to EPA’s carrying out a wide 

variety of CAA provisions. As discussed 

in the initial proposed rule (74 FR 

16448, April 10, 2009), section 114(a)(1) 

of the CAA authorizes the Administrator 

to require emissions sources, persons 


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subject to the CAA, manufacturers of 

control equipment, or persons whom 

the Administrator believes may have 

necessary information to monitor and 

report emissions and provide such other 

information the Administrator requests 

for the purposes of carrying out any 

provision of the CAA. 

EPA notes that comments were 

submitted on the initial rule proposal 

questioning EPA’s authority under the 

Clean Air Act to collect emissions 

information from certain offshore 

petroleum and natural gas platforms. 

Some commenters argued that EPA does 

not have the authority to collect 

emissions information from offshore 

platforms located in areas of the 

Western Gulf because they are under the 

jurisdiction of the Department of the 

Interior. They cited, among other things, 

the Outer Continental Shelf Act, 43 

U.S.C. 1334. Without opining on the 

accuracy of the commenter’s summary 

of OCSLA or other law, we note that 

even the commenter describes these 

authorities as relating to the regulation 

of air emissions. Today’s proposal does 

not regulate GHG emissions; rather it 

gathers information to inform EPA’s 

evaluation of various CAA provisions. 

Moreover, EPA’s authority under CAA 

Section 114 is broad, and extends to any 

person ‘‘who the Administrator believes 

may have information necessary for the 

purposes’’ of carrying out the CAA, even 

if that person is not subject to the CAA. 

Indeed, by specifically authorizing EPA 

to collect information from both persons 

subject to any requirement of the CAA, 

as well as any person who the 

Administrator believes may have 

necessary information, Congress clearly 

intended that EPA could gather 

information from a person not otherwise 

subject to CAA requirements. EPA is 

comprehensively considering how to 

address climate change under the CAA, 

including both regulatory and nonregulatory options. The information 

from these and other offshore platforms 

will inform our analyses, including 

options applicable to emissions of any 

offshore platforms that EPA is 

authorized to regulate under the CAA. 

EPA is proposing to amend 40 CFR 

98.2(a) so that the final MRR applies to 

facilities located in the United States 

and on or under the Outer Continental 

Shelf. These revisions are necessary to 

ensure that any petroleum or natural gas 

platforms located on our under the 

Outer Continental Shelf of the United 

States would be required to report under 

this rule. In addition, EPA is proposing 

revisions to the definition of United 

States to clarify that the United States 

includes the territorial seas. Other 

facilities located offshore of the United 

States covered by the mandatory 

reporting program at 40 CFR part 98 

would also be affected by this change in 

the definition of United States. Revising 

the definition of United States will also 

ensure that facilities located offshore of 

the United States that are injecting CO2

into sub-seabed for long-term 

containment will also be required to 

report data regarding greenhouse gases. 

EPA is proposing a separate rule on 

geologic sequestration and any 

comments specific to that issue should 

be directed to the Agency on that 

rulemaking not this one. Finally, in 

addition to the change to the definition 

of United States, EPA is adding a 

definition of ‘‘Outer Continental Shelf.’’ 

This definition is drawn from the 

definition in the U.S. Code. Together, 

these changes make clear that the 

Mandatory GHG Reporting Rule applies 

to facilities on land, in the territorial 

seas, or on or under the Outer 

Continental Shelf, of the United States, 

and that otherwise meet the 

applicability criteria of the rule. 

For further information about EPA’s 

legal authority, see the proposed and 

final MRR. 

D. Relationship to Other Federal, State 

and Regional Programs 

In developing the initial proposal for 

mandatory reporting from petroleum 

and natural gas systems that was 

released in April 2009, as well as this 

supplemental proposed rulemaking, 

EPA reviewed monitoring methods 

included in international guidance (e.g., 

Intergovernmental Panel on Climate 

Change), as well as Federal voluntary 

programs (e.g., EPA Natural Gas STAR 

Program and the U.S. Department of 

Energy Voluntary Reporting of 

Greenhouse Gases Program (1605(b)), 

corporate protocols (e.g., World 

Resources Institute and World Business 

Council for Sustainable Development 

GHG Protocol) and industry guidance 

(e.g., methodological guidance from the 

American Petroleum Institute, the 

Interstate Natural Gas Association of 

America, and the American Gas 

Association). 

EPA also reviewed State reporting 

programs (e.g., California and New 

Mexico) and Regional partnerships (e.g., 

The Climate Registry, the Western 

Regional Air Partnership). These are 

important programs that not only led 

the way in reporting of GHG emissions 

before the Federal government acted but 

also assist in quantifying the GHG 

reductions achieved by various policies. 

Many of these programs collect different 

or additional data as compared to this 

proposed rule. For example, State 

programs may establish lower 

thresholds for reporting, request 

information on areas not addressed in 

EPA’s reporting rule, or include 

different data elements to support other 

programs (e.g., offsets). For further 

discussion on the relationship of this 

proposed rule to other programs, refer to 

the preamble to the Final MRR. 

II. Rationale for the Reporting, 

Recordkeeping and Verification 

Requirements 

A. Overview of Proposal 

The U.S. petroleum and natural gas 

industry encompasses hundreds of 

thousands of wells, hundreds of 

processing facilities, and over a million 

miles of transmission and distribution 

pipelines. This proposed rule would 

apply to the calculation and reporting of 

vented, fugitive, and flare combustion 

emissions from selected equipment at 

the following facilities that emit equal to 

or greater than 25,000 metric tons of 

CO2 equivalent per year from source 

categories covered by the mandatory 

GHG reporting rule: offshore petroleum 

and natural gas production facilities, 

onshore petroleum and natural gas 

production facilities (including 

enhanced oil recovery (EOR)), onshore 

natural gas processing facilities, onshore 

natural gas transmission compression 

facilities, onshore natural gas storage 

facilities, LNG storage facilities, LNG 

import and export facilities and natural 

gas distribution facilities owned or 

operated by local distribution 

companies (LDCs). This proposal does 

not address the production of gas from 

landfills or manure management 

systems. Methods and reporting 

procedures for stationary combustion 

emissions other than flares at petroleum 

and natural gas industry facilities are 

covered under Subpart C of the Final 

MRR. 

This proposed supplemental rule 

incorporates a number of different 

methodologies to provide improved 

emissions coverage at a lower cost 

burden to affected facilities, as 

compared to the initial proposed rule. In 

this supplemental proposal, EPA is 

requiring the use of direct measurement 

of emissions for only the most 

significant emissions sources where 

other options are not available, and 

proposing the use of engineering 

estimates, emissions modeling software, 

and leak detection and publicly 

available emission factors for most other 

vented and fugitive sources. For smaller 

fugitive and inaccessible to plain view 

sources, component count and 

population emissions factors are 

proposed. In the case of offshore 

platforms, EPA is recommending that 


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2Since we are proposing to change the list of 

covered subcategories to tables, we are not 

providing regulatory text in this proposal because 

the preamble is clear. 

3Some petroleum and natural gas facilities will 

already be required to report emissions from 

stationary combustion under the MRR that was 

emissions sources identified under the 

Minerals Management Services (MMS) 

GOADS (Gulfwide Offshore Activities 

Data System) be used for reporting, and 

the GOADS process be extended to 

platforms in other Federal regions (i.e., 

California and Alaska) and in State 

waters. The alternative methodologies 

proposed in this rule will provide 

similar or better estimation of vented 

and fugitive CH4 and CO2 emissions in 

the petroleum and gas industry, while 

significantly reducing industry burden. 

Under this supplemental proposal, 

facilities not already reporting but 

required to report under subpart W 

would begin data collection in 2011 

following the methods outlined in the 

proposed rule, and submit data to EPA 

by March 31, 2012. 

EPA would require reporting of 

calendar year 2011 emissions in 2012 

because the data are crucial to the 

timely development of future GHG 

policy and regulatory programs. In the 

Appropriation Act, Congress requested 

EPA to develop this reporting program 

on an expedited schedule, and 

Congressional inquiries along with 

public comments reinforce that data 

collection for calendar year 2011 is a 

priority. Delaying data collection until 

calendar year 2012 would mean the data 

would not be received until 2013, which 

would likely be too late for many 

ongoing GHG policy and program 

development needs. 

EPA considered, but decided not to 

propose, the use of best available 

monitoring methods for part (e.g., the 

first three months) or all of the first year 

of data collection. EPA concluded that 

the time period that would be allowed 

under this schedule is sufficient to 

allow facilities to implement the 

monitoring methods that would be 

required by the proposed rule. In 

general, the proposed monitors are 

widely available and are not time 

consuming to install. Further, some of 

the monitoring methods (e.g., use of 

emission factors) may not require the 

installation of any monitoring 

equipment. Finally, the emissions 

assessment may be done at any time 

during the year, and measurements do 

not necessarily need to be undertaken 

during the first quarter. 

EPA seeks comment on the proposal 

not to allow use of best available 

monitoring methods for part or all of the 

first year of data collection. Further, if 

commenters recommend that EPA allow 

the use of best available monitoring 

methods for a designated time period 

(e.g., three months), EPA seeks 

comments on whether requests for use 

of best available monitoring methods 

should only be approved for parameters 

subject to direct measurement, or also in 

cases where engineering calculations 

and/or emission factors are used. 

Amendments to the General 

Provisions. In a separate rulemaking 

package that was recently published 

(March 16, 2010), EPA issued minor 

harmonizing changes to the general 

provisions for the GHG reporting rule 

(40 CFR part 98, subpart A) to 

accommodate the addition of source 

categories not included in the 2009 final 

rule (e.g., subparts proposed in April 

2009 but not finalized in 2009, any new 

subparts that may be proposed in the 

future). The changes update 98.2(a) on 

rule applicability and 98.3 regarding the 

reporting schedule to accommodate any 

additional subparts and the schedule for 

their reporting obligations (e.g., source 

categories finalized in 2010 would not 

begin data collection until 2011 and 

reporting in 2012). 

In particular, we restructured 40 CFR 

98.2(a) to move the lists of source 

categories from the text into tables. A 

table format improves clarity and 

facilitates the addition of source 

categories that were not included in 

calendar year 2010 reporting and would 

begin reporting in future years. A table, 

versus list, approach allows other 

sections of the rule to be updated 

automatically when the table is 

updated; a list approach requires 

separate updates to the various list 

references each time the list is changed. 

In addition to reformatting the 

98.2(a)(1)–(2) lists into tables, other 

sections of subpart A were reworded to 

refer to the source category tables 

because the tables make it clear which 

source categories are to be considered 

for determining the applicability 

threshold and reporting requirements 

for calendar years 2010, 2011, and 

future years. 

Because facilities with petroleum and 

natural gas systems (as defined in 

proposed 40 CFR part 98, subpart W) 

would be subject to the rule if facility 

emissions exceed 25,000 metric tons 

CO2e per year, in today’s rule we are 

proposing to add this source category to 

those threshold categories referenced 

from 40 CFR 98.2(a)(2) whether the 

reference is to a list or a table.2

In today’s proposal, we also propose 

to amend 40 CFR 98.6 to add definitions 

for several terms used in proposed 40 

CFR part 98, subpart W and to clarify 

the meaning of certain terms for 

purposes of subpart W. We also propose 

to amend 40 CFR 98.7 (incorporation by 

reference) to include standard methods 

used in proposed subpart W. In 

particular, we propose to incorporate by 

reference the AAPG–CSD Geologic Code 

Provinces Code Map available from The 

American Association of Petroleum 

Geologists Bulletin, Volume 75, No. 10 

(October 1991) pages 1644–1651. It 

would be used to define the geographic 

boundaries for reporting of onshore oil 

and gas production systems. We also 

proposed to incorporate by reference 

models, including Glycalc and E&P 

Tanks that would be used to calculate 

emissions and were not developed by 

the Federal government. 

B. Summary of the Major Changes Since 

Initial Proposal 

Mandatory GHG reporting 

requirements were proposed for 

Petroleum and Natural Gas Systems 

under Subpart W in April 2009 along 

with a number of other sectors of the 

economy. As noted in the Preamble to 

the Final MRR, EPA received a number 

of lengthy, detailed comments regarding 

Petroleum and Natural Gas Systems. In 

total, EPA received comments from over 

80 organizations and over 1,200 pages of 

formal comments on the Petroleum and 

Gas Systems Initial Proposed Rule. 

Some comments proposed simplified 

alternatives to the proposed reporting 

requirements based on the potential that 

the proposed requirements would entail 

significant burden and cost. Other 

comments addressed whether to include 

onshore production and the distribution 

segment, which were excluded from the 

initial proposal as EPA sought 

comments on approaches for the level of 

reporting of fugitive and vented GHG 

emissions from these segments (e.g., 

facility or corporate). 

EPA has reviewed the comments and 

issues and suggestions raised by 

stakeholders within and outside the 

petroleum and natural gas industry 

related to emissions coverage and the 

level of cost burden in this sector. In 

response, EPA is proposing a new 

supplemental rule for Petroleum and 

Natural Gas Systems. This proposed 

supplemental rule now incorporates all 

segments of the petroleum and gas 

industry, adding onshore production 

and distribution. 

Total fugitive, vented and combustion 

emissions estimated to be covered in 

this supplemental proposed rulemaking 

amount to 351 MMTCO2e; 272 

MMTCO2e from fugitive and vented 

emissions and 79 MMTCO2e from 

combustion emissions.3 Fugitive and 


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Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 18613 

signed in September 2009. This proposed 

petroleum and natural gas subpart will require 

additional facilities to report to the MRR that are 

not currently required to report. These facilities will 

have to report combustion, fugitive and vented 

emissions. These incremental combustion 

emissions are estimated at 79 MMTCO2e. 

vented emissions estimates included in 

the supplemental proposed rulemaking 

are significantly higher than the 131 

MMTCO2e reported in the 2008 U.S. 

Inventory of Greenhouse Gases, due to 

the inclusion of items believed to be 

under-reported in the inventory 

(discussed further below). 

Table W–1 summarizes the estimated 

fugitive, vented and combustion 

emissions for the segments included in 

the initial proposal and the added 

segments of onshore production and 

distribution. Additional details can be 

found in the Economic Impact Analysis 

for the Mandatory Reporting of 

Greenhouse Gas Emissions under 

Subpart W Supplemental Rule (EPA– 

HQ–OAR–2009–0923). 

TABLE W–1—FUGITIVE/VENTED AND COMBUSTION EMISSIONS FROM PETROLEUM AND NATURAL GAS SYSTEMS, 

MMTCO2e 

Segment 

Fugitive and 

vented emissions: 

Initial proposed rule 

Fugitive and 

vented emissions: Supplemental proposed rulemaking 

Combustion 

emissions: 

Supplemental 

proposed rulemaking 

Initial Proposed Rule Six Segments ............................................................................................ 85 94.3 9.8 

Onshore Production ..................................................................................................................... NA 154.9 69.3 

Natural Gas Distribution .............................................................................................................. NA 22.7 NA 

Total Emissions .................................................................................................................... 85 271.9 1 79.1 

1This estimate reflects only incremental combustion emissions (i.e., only those combustion emissions from facilities above and beyond what 

will already be required to be reported under the Final MRR). For example, combustion-related emissions ftrom many natural gas processing 

plants are already required to be reported under subpart C and are therefore not included here. The combustion estimate also includes combustion emissions from flares. 

Inclusion of onshore production and 

distribution results in estimated fugitive 

and vented emissions that are more than 

triple the estimated emissions in the 

initial rule proposal for petroleum and 

natural gas systems. 

In addition to expanding emissions 

coverage under the proposed 

supplemental rule, EPA has assessed a 

number of alternative methodologies 

that were either recommended by 

commenters or are known to provide 

effective quantification of emissions at a 

significantly lower cost burden. The 

changes include the use of: 

• Limited use of fugitive leak 

detection. 

• Leaker factors to quantify detected 

fugitive emissions. 

• Population factors and component 

count for fugitive emissions that are 

widely scattered or inaccessible to plain 

view. 

• Use of existing MMS GOADS 

methods and calculated emissions for 

offshore production facilities. 

• Modeling software to quantify 

glycol dehydrator and tank emissions. 

• Engineering estimation for well 

venting from liquids unloading. 

• Engineering estimation for well 

venting from completions and 

workovers. 

• Engineering estimation for well 

testing and flaring. 

• Engineering estimation for flaring 

emissions. 

• Limited sampling to determine gas 

composition. 

Another significant change in the 

proposed supplemental rule is the use 

of the term ‘‘fugitives’’. The initial rule 

proposal from April 2009 included both 

vented and fugitive emissions sources, 

and collectively defined both sources as 

‘‘fugitive’’. EPA received a large number 

of comments from industry stakeholders 

and others indicating that this definition 

created confusion. Hence EPA is 

defining vented emissions separately 

from fugitives in the supplemental 

proposed rulemaking. For this 

supplemental rulemaking, emissions 

from the petroleum and natural gas 

industry are defined as (1) vented 

emissions, which include intentional or 

designed releases of CH4 and/or CO2

containing natural gas or hydrocarbon 

gas (not including stationary 

combustion flue gas) from emissions 

sources including, but not limited to, 

process designed flow to the atmosphere 

through seals or vent pipes, equipment 

blowdown for maintenance, and direct 

venting of gas used to power equipment 

(such as pneumatic devices). In 

addition, this supplemental rule 

includes (2) fugitive emissions, or 

unintentional emissions, which are 

defined to include those emissions 

which could not reasonably pass 

through a stack, chimney, vent, or other 

functionally-equivalent opening. This 

supplemental rule also includes (3) flare 

combustion emissions, which include 

CH4, CO2 and N2O emissions resulting 

from combustion of gas in flares. EPA 

seeks comment on the use of the term 

‘‘equipment leak’’ versus ‘‘fugitive’’ and 

‘‘vented’’ as defined in the proposed 

supplemental rule. 

C. Definition of the Source Category 

EPA discusses here the general 

approach used in identifying the key 

segments of the petroleum and natural 

gas industry that would be required to 

report under the proposal. This general 

discussion is followed by a specific 

discussion for each industry segment. 

One factor EPA considered in 

assessing the applicability of certain 

petroleum and natural gas industry 

emissions in the proposed rule is the 

definition of a facility. In other words, 

what physically constitutes a facility? 

This definition is important to 

determine the reporting entity, to ensure 

that delineation is clear, and to 

minimize double counting or omissions 

of emissions. For some segments of the 

industry (e.g., onshore natural gas 

processing facilities, natural gas 

transmission compression facilities, and 

offshore petroleum and natural gas 

facilities), identifying the facility is clear 

since there are physical boundaries and 

ownership structures that lend 

themselves to identifying scope of 

reporting and responsible reporting 

entities. In other segments of the 

industry (e.g., the pipelines between 

compressor stations and onshore 

petroleum and natural gas production) 

such distinctions are not as 


srobinson on DSKHWCL6B1PROD with PROPOSALS3
18614 Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 

4The denominator includes total fugitive and 

vented emissions, as well as any additional 

combustion related emissions that will be required 

to be reported by the petroleum and natural gas 

industry and that wasn’t already covered in the 

final MRR. 

straightforward. In defining a facility, 

EPA reviewed current definitions used 

in the Clean Air Act (CAA), ISO 

definitions, comments provided under 

the initial proposed rule, and current 

regulations relevant to the industry. A 

complete description of our assessment 

can be found in Greenhouse Gas 

Emissions from the Petroleum and 

Natural Gas Industry: Background 

Technical Support Document (TSD) 

(EPA–HQ–OAR–2009–0923). 

At the same time, EPA also decided 

that it was impractical to include each 

of the over 160 different sources of 

vented and fugitive CH4 and CO2

emissions in the petroleum and natural 

gas industry. In response to comments 

received on the initial proposed rule, 

EPA undertook a systematic review of 

each emissions source included in the 

2008 U.S. GHG Inventory in order to 

propose reporting of only the most 

significant emissions sources (e.g. 

emissions that account for the majority 

of oil and gas fugitive and vented 

emissions). In determining the most 

relevant vented and fugitive emissions 

sources for inclusion in this 

supplemental proposed rulemaking, 

EPA considered the following criteria: 

The coverage of emissions for the source 

category as a whole; the coverage of 

emissions per unit of the source 

category; the feasibility of a viable 

monitoring method, including direct 

measurement and engineering 

estimations; and the number of facilities 

that would be required to report. 

Sources that contribute significantly 

large emissions were considered for 

inclusion in this supplemental proposed 

rulemaking, since they increase the 

coverage of emissions reporting. 

Typically, at petroleum and gas 

facilities, 80 percent or more of a 

facility’s emissions come from 

approximately 10 percent of the 

emissions sources. EPA used this 

benchmark to reduce the number of 

emissions sources required for reporting 

while keeping the reporting burden to a 

minimum. Sources in each segment of 

the petroleum and natural gas industry 

were sorted into two main categories: (1) 

The largest sources contributing to 

approximately 80 percent of the 

emissions from the segment, and (2) the 

sources contributing to the remaining 20 

percent of the emissions from that 

particular segment. EPA assigned 

sources into these two groups by 

determining the emissions contribution 

of each emissions source to its relevant 

segment of the petroleum and gas 

industry, listing the emissions sources 

in a descending order, and identifying 

all the sources at the top that contribute 

to approximately 80 percent of the 

emissions. Generally, those sources that 

fell into approximately the top 80 

percent were considered for inclusion. 

Details of the analysis can be found in 

Greenhouse Gas Emissions from the 

Petroleum and Natural Gas Industry: 

Background TSD (EPA–HQ–OAR–2009– 

0923). 

The following is a brief discussion of 

the proposed emission sources to be 

included and excluded based on our 

analysis. Additional information can be 

found in Greenhouse Gas Emissions 

from the Petroleum and Natural Gas 

Industry: Background TSD (EPA–HQ– 

OAR–2009–0923. Note that this subpart 

of the GHG reporting rule addresses 

only vented, fugitive and flare 

combustion emissions. As mentioned 

previously, stationary combustion 

emissions are included in Subpart C of 

the Final MRR Preamble. 

Onshore Petroleum and Natural Gas 

Production 

The onshore petroleum and natural 

gas production segment uses wells to 

extract raw natural gas, condensate, 

crude oil, and associated gas from 

underground formations and inject CO2

for EOR. Extraction includes several 

types of processes: Reservoir 

management, primary recovery, 

secondary recovery such as down-hole 

pumps, water flood or natural gas/ 

nitrogen/immiscible CO2 injection, and 

tertiary recovery such as using critical 

phase miscible CO2 injection. The 

largest sources of CH4 and CO2

emissions include, but are not limited 

to, natural gas driven pneumatic devices 

and pumps, field crude oil and 

condensate storage tanks, glycol 

dehydration units, releases and flaring 

during well completions, well 

workovers, and well blowdowns for 

liquids unloading, releases and flaring 

of associated gas, and blowdowns of 

compressors and EOR pumps. 

EPA is proposing to include the 

onshore petroleum and natural gas 

production segment due to the fact that 

these operations represent a significant 

emissions source, representing 

approximately 66 percent of fugitive, 

vented and incremental4 combustion 

emissions from the petroleum and 

natural gas segments covered by the 

proposed rule. 

EPA considered a range of possible 

options for reporting emissions from 

onshore petroleum and natural gas 

facilities. Although several options for 

defining the facility were considered 

and described below, EPA has 

determined that only two of the options 

are feasible: Basin-level reporting and 

field-level reporting. For this 

supplemental proposed rulemaking, 

EPA proposes that emissions from 

onshore petroleum and natural gas 

production be reported at the basin 

level. The reporting entity for onshore 

petroleum and natural gas production 

would be the operating entity listed on 

the state well drilling permit, or a state 

operating permit for wells where no 

drilling permit is issued by the state, 

who operates onshore petroleum and 

natural gas production wells and 

controls by means of ownership 

(including leased and rented) and 

operation (including contracted) 

stationary and portable (as defined in 

this Subpart) equipment located on all 

well pads within a single hydrocarbon 

basin as defined by the American 

Association of Petroleum Geologists 

(AAPG) three-digit Geological Province 

Code. The equipment referenced above 

includes all structures associated with 

wells used in the production, extraction, 

recovery, lifting, stabilization, 

separation or treating of petroleum and/ 

or natural gas (including condensate) 

including equipment that is leased, 

rented or contracted. This includes 

equipment such as compressors, 

generators or storage facilities, piping 

(such as flowlines or intra-facility 

gathering lines), and portable non-selfpropelled equipment (such as well 

drilling and completion equipment, 

workover equipment, gravity separation 

equipment, auxiliary nontransportation-related equipment). This 

also includes associated storage or 

measurement equipment and all 

equipment engaged in gathering 

produced gas from multiple wells, EOR 

operations using CO2, and all petroleum 

and natural gas production operations 

located on islands, artificial islands or 

structures connected by a causeway to 

land, an island, or artificial island. 

Where more than one entity may hold 

the state well drilling permit, or well 

operating permit where no drilling 

permit is issued by the state, the 

permitted entities for the facility would 

be required to designate one entity to 

report all emissions from the jointly 

controlled facility. Where an operating 

entity holds more than one permit to 

operate wells in a basin, then all 

onshore petroleum and natural gas 

production well permits in their name 

in the basin, including all equipment on 

the well pads, would be considered one 

onshore petroleum and natural gas 


srobinson on DSKHWCL6B1PROD with PROPOSALS3
Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 18615 

5The denominator includes total fugitive and 

vented emissions, as well as any additional 

combustion related emissions that will be required 

to be reported by the petroleum and natural gas 

industry and that wasn’t already covered in the 

final MRR. 

production facility for purposes of 

reporting. 

There are at least two industry 

recognized definitions available that 

identify hydrocarbon basins; one from 

the United State Geological Survey 

(USGS) and the other from the AAPG. 

The AAPG geologic definition is 

referenced to county boundaries and 

hence likely to be familiar to the 

industry, i.e. if the owner or operator 

knows in which county their well is 

located, then they know to which basin 

they belong. Basins are mapped to 

county boundaries only to give a surface 

manifestation to the underground 

geologic structures, thus making it 

easier to relate surface facilities to basin 

underground geologic boundaries. On 

the other hand, the USGS definition is 

based purely on the geology of the 

hydrocarbon basin without 

consideration of state and county 

boundaries. Hence using the USGS 

definition may make it more difficult to 

map surface operations to a particular 

basin. Therefore, EPA is proposing to 

use the AAPG definition of a basin. EPA 

seeks comments on the availability of 

other appropriate standard basin level 

definitions that could be applied for the 

purposes of this rule and their merits 

over the AAPG definition. 

EPA is proposing a basin level 

approach, because the boundaries for 

reporting are clearly defined and the 

approach covers approximately 81 

percent of emissions from onshore 

petroleum and natural gas production. 

EPA evaluated and is taking comment 

on one alternative option for reporting 

from onshore petroleum and natural gas 

production; field level. Field level 

reporting would require aggregation of 

emissions from all covered equipment at 

onshore petroleum and natural gas 

production facilities at the field level, as 

opposed to the basin level as described 

above. A typical field level definition is 

available from the Energy Information 

Administration Oil and Gas Field Code 

Master. As outlined in the Economic 

Impact Analysis for this proposed rule, 

the field level option would result in a 

significantly lower coverage in 

emissions, estimated at 55 percent in 

comparison to the basin level coverage 

of 81 percent. In essence the two 

reporting options are not different from 

a methodological point of view because 

both definitions rely on geographical 

boundaries. Therefore, EPA has 

proposed the use of a basin level 

definition to increase coverage. EPA 

seeks comments on our decision to 

propose the basin level approach, and 

whether there would be advantages to 

requiring reporting at the field level 

instead. 

In addition to basin and field level 

reporting, EPA considered one other 

alternative approach for defining a 

facility for onshore petroleum and 

natural gas production; individual well 

pads. This well pad approach included 

all stationary and portable equipment 

operating in conjunction with that well, 

including drilling rigs with their 

ancillary equipment, gas/liquid 

separators, compressors, gas 

dehydrators, crude oil heater-treaters, 

gas powered pneumatic instruments and 

pumps, electrical generators, steam 

boilers and crude oil and gas liquids 

stock tanks. This definition was 

analyzed with available data including 

four cases to represent the full range of 

petroleum and natural gas well pad 

operations ranging from unconventional 

well drilling and operation starting in 

the beginning of the year with higher 

emitting practices, to production at an 

associated gas and oil well (no drilling) 

with minimal equipment and a vapor 

recovery unit. 

EPA analyzed the average emissions 

associated with each of the four well 

pad facility cases and determined that 

average emissions at these operations 

were low (from about 370 metric tons of 

CO2e per year to slightly less than 5,000 

metric tons of CO2e per year). This 

analysis shows that the threshold would 

have to be set at less than 400 metric 

tons CO2e per year to capture the largest 

possible amount of onshore production 

emissions (only 33 percent) which 

would result in close to 170,000 

reporters. Additional information can be 

found in Greenhouse Gas Emissions 

from the Petroleum and Natural Gas 

Industry: Background TSD (EPA–HQ– 

OAR–2009–0923). If the threshold was 

set at approximately 5,000 metric tons, 

EPA estimates that the number of 

reporters would decrease significantly 

to approximate 3,300 but the emission 

coverage would be only 6 percent. 

Based on the results above, EPA did not 

consider the well pad definition further 

in the Economic Impact Analysis. 

Offshore Petroleum and Natural Gas 

Production 

Offshore petroleum and natural gas 

production is any platform structure, 

affixed temporarily or permanently to 

offshore submerged lands, that houses 

equipment to extract hydrocarbons from 

the ocean or lake floor and that transfers 

such hydrocarbons to storage, transport 

vessels, or onshore. In addition, offshore 

production includes secondary platform 

structures and storage tanks associated 

with the platform structure. GHG 

emissions result from sources housed on 

the platforms. 

In 2006, offshore petroleum and 

natural gas production CO2 and CH4

emissions accounted for 5.1 million 

metric tons CO2e. The primary sources 

of emissions from offshore petroleum 

and natural gas production are from 

valves, flanges, open-ended lines, 

compressor seals, platform vent stacks, 

and other source types. Flare stacks 

account for the majority of combustion 

CO2 emissions. 

Offshore petroleum and natural gas 

production facilities are proposed for 

inclusion due to the fact that this 

segment represents approximately 1.9 

percent of fugitive, vented and 

incremental 5 combustion emissions 

from the petroleum and natural gas 

industry, an existing activity data 

collection system already exists that can 

readily be used to calculate GHG 

emissions (i.e., GOADS) and major 

fugitive and vented emissions sources 

can be characterized by an existing 

reasonable methodology which will 

minimize incremental burden for 

reporters. This is consistent with 

comments received on the initial 

proposed rule. 

Onshore Natural Gas Processing 

Natural gas processing facilities 

remove hydrocarbon and water liquids 

and various other constituents (e.g., 

hydrogen sulfide, carbon dioxide, 

helium, nitrogen, and hydrocarbons 

heavier than methane) from the 

produced natural gas. The resulting 

‘‘pipeline quality’’ natural gas is 

transported to transmission pipelines. 

Natural gas processing facilities also 

include gathering/boosting stations that 

dehydrate and compress natural gas to 

be sent to natural gas processing 

facilities or directly to natural gas 

transmission or distribution systems. 

Compressors are used within gathering/ 

boosting stations to adequately 

pressurize the natural gas so that it can 

be transported to natural gas processing, 

transmission, and distribution facilities 

through gathering pipelines. In addition, 

compressors at natural gas processing 

facilities are used to boost natural gas 

pressure so that it can pass through all 

of the processes and into the highpressure transmission pipelines. 

Vented and fugitive CH4 emissions 

from reciprocating and centrifugal 

compressors, including centrifugal 

compressor wet and dry seals, wet seal 

oil degassing vents, reciprocating 

compressor rod packing vents, and all 


srobinson on DSKHWCL6B1PROD with PROPOSALS3
18616 Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 

6The denominator includes total fugitive and 

vented emissions, as well as any additional 

combustion related emissions that will be required 

to be reported by the petroleum and natural gas 

industry and that wasn’t already covered in the 

final MRR. 

7The denominator includes total fugitive and 

vented emissions, as well as any additional 

combustion related emissions that will be required 

to be reported by the petroleum and natural gas 

industry and that wasn’t already covered in the 

final MRR. 

other compressor emissions, are the 

primary CH4 emission sources from this 

segment. The majority of vented CO2

emissions come from acid gas removal 

vent stacks, which are designed to 

remove CO2 and hydrogen sulfide, when 

present, from natural gas. While these 

are the major emissions sources in 

natural gas processing facilities, other 

potential sources such as dehydrator 

vent stacks, piping connectors, openended vent and drain lines and 

gathering pipelines associated with the 

processing plant would also need to be 

reported under the proposed 

supplemental rule. 

Onshore natural gas processing 

facilities are proposed for inclusion due 

to the fact that these operations 

represent a significant emissions source, 

approximately 8 percent of fugitive, 

vented and incremental 6 combustion 

emissions from the natural gas segment, 

methods are available to estimate 

emissions, and there are a reasonable 

number of reporters. Most natural gas 

processing facilities proposed for 

inclusion in this supplemental proposed 

rulemaking would already be required 

to report under subpart C and/or subpart 

NN of the Final MRR. 

Onshore Natural Gas Transmission 

Compression Facilities and 

Underground Natural Gas Storage 

Natural gas transmission compression 

facilities move natural gas throughout 

the U.S. natural gas transmission 

system. Natural gas is also injected and 

stored in underground formations 

during periods of low demand (e.g., 

spring or fall) and withdrawn, 

processed, and distributed during 

periods of high demand (e.g., winter or 

summer). Storage compressor stations 

are dedicated to gas injection and 

extraction at underground natural gas 

storage facilities. 

Vented and fugitive CH4 emissions 

from reciprocating and centrifugal 

compressors, including compressor and 

station blowdowns, centrifugal 

compressor wet and dry seals, wet seal 

oil degassing vents, reciprocating 

compressor rod packing vents, unit 

isolation valves, blowdown valves, 

compressor scrubber dump valves, gas 

pneumatic continuous bleed devices 

and all other compressor fugitive 

emissions, are the primary CH4 emission 

source from natural gas transmission 

compression stations and underground 

natural gas storage facilities. 

Dehydrators are also a significant source 

of CH4 emissions from underground 

natural gas storage facilities. While 

these are the major emissions sources in 

natural gas transmission, other potential 

sources include, but are not limited to, 

condensate (water and hydrocarbon) 

tanks, open-ended lines and valve stem 

seals. Condensate tank vents in 

transmission can be a significant source 

of emissions from malfunctioning 

compressor scrubber dump valves and 

will require detection of such leakage by 

an optical imaging instrument and 

direct measurement where found 

present. 

Onshore natural gas transmission 

compression facilities and underground 

natural gas storage facilities are 

proposed for inclusion due to the fact 

that these operations represent 

significant sources of fugitive, vented 

and incremental 7 combustion 

emissions, 15 and 2 percent, 

respectively, methods are available to 

estimate emissions, and there are a 

reasonable number of reporters. Further, 

this segment was included in the initial 

proposed rule and EPA has made 

improvements to the proposal based on 

comments received. 

LNG Import and Export and LNG 

Storage 

The U.S. imports and exports natural 

gas in the form of LNG, which is 

received, stored, and, when needed, regasified at LNG import and export 

terminals. Import and export include 

both LNG movements between U.S. and 

foreign sources as well as transport 

between U.S. sources. LNG storage 

facilities liquefy and store natural gas 

from processing plants and transmission 

pipelines during periods of low demand 

(e.g., spring or fall) and re-gasify for 

send out during periods of high demand 

(e.g., summer and winter) 

Fugitive and vented CH4 and CO2

emissions from reciprocating and 

centrifugal compressors, including 

centrifugal compressor wet and dry 

seals, wet seal degassing vents, 

reciprocating compressor rod packing 

vents, and all other compressor fugitive 

emissions, are the primary CH4 and CO2

emission source from LNG storage 

facilities and LNG import and export 

facilities. Process units at these facilities 

can include vapor recovery compressors 

to re-liquefy natural gas tank boil-off (at 

LNG storage facilities), re-condensers, 

vaporization units, tanker unloading 

equipment (at LNG import terminals), 

transportation pipelines, and/or LNG 

pumps. 

LNG storage ‘‘facilities’’ can be defined 

as facilities that store liquefied natural 

gas in above ground storage tanks. LNG 

import terminal can be defined as 

onshore or offshore facilities that 

receive imported LNG via ocean 

transport, store it in storage tanks, regasify it, and deliver re-gasified natural 

gas to a natural gas transmission or 

distribution system. LNG export 

terminal (facility) can be defined as 

onshore or offshore facilities that 

receive natural gas, liquefy it, store it in 

storage tanks, and send out the LNG via 

ocean transportation, including to 

import facilities in the United States. 

EPA is proposing inclusion of these 

facilities because the National Inventory 

has very little data on methane 

emissions in these segments which are 

expected to grow substantially in 

forward years. 

Petroleum and Natural Gas Pipelines 

Natural gas transmission involves 

high pressure, large diameter pipelines 

that transport gas long distances from 

field production and natural gas 

processing facilities to natural gas 

distribution pipelines or large volume 

customers such as power plants or 

chemical plants. Crude oil 

transportation involves pump stations 

and bulk tank terminals to move crude 

oil through pipelines and loading and 

unloading crude oil tanks, marine 

vessels, and railroad tank cars. The 

majority of vented and fugitive 

emissions from the transportation of 

natural gas occur at the compressor 

stations, which are proposed for 

inclusion in the supplemental rule and 

discussed above. 

EPA is not proposing to include 

reporting of fugitive emissions from 

natural gas pipeline segments between 

compressor stations, or crude oil 

pipelines and tank terminals in the 

supplemental rulemaking due to the 

dispersed nature of the fugitive 

emissions, and the fact that once 

fugitives are found, the emissions are 

generally addressed quickly. For natural 

gas gathering pipelines, EPA is 

proposing that producers who own or 

operate gathering lines associated with 

their production fields and natural gas 

processors who own or operate 

gathering lines associated with their 

processing plants should include those 

gathering lines in their field or 

processing plant reported emissions. 

Natural Gas Distribution 

Natural gas distribution facilities are 

local distribution companies (LDCs) that 


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8The denominator includes total fugitive and 

vented emissions, as well as any additional 

combustion related emissions that will be required 

to be reported by the petroleum and natural gas 

industry and that wasn’t already covered in the 

final MRR. 

include the above grade (above ground) 

gas metering and pressure regulation 

(M&R) equipment, M&R equipment 

below grade in vaults, buried pipelines 

and customer meters used to transport 

natural gas primarily from high pressure 

transmission pipelines to end users. In 

the distribution segment, high-pressure 

gas from natural gas transmission 

pipelines enters a ‘‘city gate’’ station, 

which reduces the pressure and 

distributes the gas through primarily 

underground mains and service lines to 

individual end users. Distribution 

system CH4 and CO2 emissions result 

mainly from fugitive emissions from 

above ground gate stations (metering 

and regulating stations), below grade 

vaults (regulator stations), and fugitive 

emissions from buried pipelines. At gate 

stations, fugitive and vented CH4

emissions primarily come from valves, 

open-ended lines, connectors, pressure 

safety valves, and natural gas driven 

pneumatic devices. CH4 emissions in 

vaults are entirely fugitive, primarily 

from piping connectors to meters and 

regulators. 

Although emissions from a single 

vault, gate station or segment of pipeline 

in the natural gas distribution segment 

may not be significant, collectively 

these emissions sources contribute a 

significant share of emissions from 

natural gas systems. 

EPA proposes to include natural gas 

distribution facilities because these 

operations represent a significant 

emissions source, approximately 6 

percent of fugitive, vented and 

incremental 8 combustion emissions 

from the petroleum and natural gas 

industry. EPA proposes that LDC’s 

would report for all of the distribution 

facilities that they own or operate. 

Crude Oil Transportation 

Crude oil is commonly transported by 

barge, tanker, rail, truck, and pipeline 

from production operations and import 

terminals to petroleum refineries or 

export terminals. Typical equipment 

associated with these operations is 

storage tanks and pumping stations. The 

major sources of CH4 and CO2 emissions 

include releases from tanks and marine 

vessel loading operations. 

EPA is not proposing to include the 

crude oil transportation segment of the 

petroleum and natural gas industry in 

this supplemental rulemaking due to its 

small contribution to total petroleum 

and natural gas CH4 and CO2 emissions, 

accounting for much less than 1 percent. 

D. Selection of Reporting Threshold 

EPA proposes that owners or 

operators of facilities with emissions 

equal to or greater than 25,000 metric 

tons CO2e per year be subject to these 

reporting requirements. This threshold 

is applicable to all petroleum and 

natural gas system reporters covered by 

this subpart: onshore petroleum and 

natural gas production facilities, 

offshore petroleum and natural gas 

production facilities, onshore natural 

gas processing facilities, including 

gathering/boosting stations; natural gas 

transmission compression facilities, 

underground natural gas storage 

facilities; LNG storage facilities; LNG 

import and export facilities and natural 

gas distribution facilities. As described 

above, under the proposed rule, for 

onshore petroleum and natural gas 

production facilities an owner or 

operator (as defined by the proposed 

rule) would evaluate emissions from all 

equipment covered by the proposed 

rule, including vented, fugitive, flared 

and stationary combustion, in a defined 

basin against the threshold to determine 

applicability. 

Consistent with the rest of the Final 

MRR, EPA is proposing that for the 

purposes of determining whether a 

facility emits equal to or greater than a 

25,000 mtCO2e, a facility must include 

emissions from all source categories for 

which methods are provided in the rule. 

EPA proposes that when a facility 

determines emissions for the purposes 

of the threshold determination under 

subpart W, that the fuel combustion 

emissions estimates include both 

stationary and portable equipment (e.g., 

compressors, drilling rigs, and 

dehydrators that are skid-mounted) that 

are controlled by well operators through 

ownership, direct operation, leased and 

rented equipment, and contracted 

operation. Fugitive, vented and 

combustion emissions from portable 

equipment are proposed for inclusion in 

the threshold determination for this 

source category due to the unique 

nature of the petroleum and natural gas 

industry. In addition to well drilling rigs 

and their ancillary equipment for well 

completions, it is common practice in 

onshore production to use skid mounted 

portable compressors, glycol 

dehydrators and other equipment partly 

for installation cost savings and partly 

because well flow rates decline over 

time and well-head equipment becomes 

over sized, and is moved around to 

match equipment capacity with wells of 

the same production capacity. 

Also due to the unique nature of the 

industry, EPA believes that it may be 

possible that onshore petroleum and 

natural gas production equipment from 

onshore petroleum and natural gas 

production facilities may be co-located 

with other manufacturing facilities 

already covered under other subparts of 

the rule (e.g., cement manufacturing 

facilities or glass manufacturing 

facilities). It is not EPA’s intent to have 

these manufacturing facilities include 

emissions from onshore petroleum and 

natural gas production equipment in 

their threshold determination. EPA 

seeks comment on this approach. 

To identify the most appropriate 

threshold level for reporting of 

emissions, EPA conducted analyses to 

determine emissions reporting coverage 

and facility reporting coverage at four 

different threshold levels: 1,000 metric 

tons CO2e per year, 10,000 metric tons 

CO2e per year, 25,000 metric tons CO2e 

per year, and 100,000 metric tons CO2e 

per year. Table W–2 provides coverage 

of emissions and number of facilities 

reporting at each threshold level for all 

the industry segments under 

consideration for this proposed 

supplemental rule. 

TABLE W–2—THRESHOLD ANALYSIS FOR EMISSIONS FROM THE PETROLEUM AND NATURAL GAS INDUSTRY

Segment 

Total national 

emissions 

Total number 

of facilities 

Threshold 

level 

Total emissions covered by 

threshold 

Facilities covered 

(metric tons 

CO2e per 

year) 

(metric tons 

CO2e per 

year) 

Percent Number Percent 

Onshore Petroleum & Gas Production 277,798,737 27,993 100,000 187,175,289 67 466 2 

25,000 224,227,559 81 1,232 4 


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TABLE W–2—THRESHOLD ANALYSIS FOR EMISSIONS FROM THE PETROLEUM AND NATURAL GAS INDUSTRY—Continued 

Segment 

Total national 

emissions 

Total number 

of facilities 

Threshold 

level 

Total emissions covered by 

threshold 

Facilities covered 

(metric tons 

CO2e per 

year) 

(metric tons 

CO2e per 

year) 

Percent Number Percent 

10,000 242,390,849 87 2,413 9 

1,000 268,848,529 97 10,604 38 

Offshore Petroleum & Gas Production 11,261,305 3,235 100,000 3,242,389 29 4 0 

25,000 5,119,405 45 58 2 

10,000 7,111,563 63 184 6 

1,000 10,553,889 94 1192 37 

Natural Gas Processing ....................... 33,984,015 566 100,000 24,874,783 73 130 23 

25,000 31,229,071 92 289 51 

10,000 32,982,975 97 396 70 

1,000 33,984,015 100 566 100 

Natural Gas Transmission Compression ................................................... 64,059,125 1,944 100,000 34,518,927 54 433 22 

25,000 57,683,144 90 1,145 59 

10,000 62,672,905 98 1,443 74 

1,000 64,051,661 100 1,695 87 

Underground Natural Gas Storage ...... 9,713,029 397 100,000 3,548,988 37 36 9 

25,000 7,846,609 81 133 34 

10,000 8,968,994 92 200 50 

1,000 9,696,532 100 347 87 

LNG Storage ........................................ 2,113,601 157 100,000 695,459 33 4 3 

25,000 1,900,793 90 33 21 

10,000 2,030,842 96 41 26 

1,000 2,096,974 99 54 34 

LNG Import and Export 2 ..................... 315,888 5 100,000 314,803 99.7 4 80 

25,000 314,803 99.7 4 80 

10,000 314,803 99.7 4 80 

1,000 315,888 100.00 5 100 

Natural Gas Distribution ....................... 25,258,347 1,427 100,000 18,470,457 73 66 5 

25,000 22,741,042 90 143 10 

10,000 23,733,488 94 203 14 

1,000 24,983,115 99 594 42 

1The emissions include fugitive and vented CH4 and CO2 and combusted CO2, N2O, and CH4 gases. The emissions for each industry segment do not match the 2008 U.S. Inventory either because of added details in the estimation methodology or use of a different methodology than 

the U.S. Inventory. For additional discussion, refer to Greenhouse Gas Emissions from the Petroleum and Natural Gas Industry: Background 

TSD (EPA–HQ–OAR–2009–0923). 2The analysis included only import facilities. There is only one export facility, located in Kenai, Alaska. 


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EPA is proposing a threshold of 

25,000 metric tons CO2e applied to 

those emissions sources listed in Table 

W–2, which will cover approximately 

83 percent of estimated vented and 

fugitive emissions and incremental 

combustion emissions from facilities 

that did not meet the reporting 

requirements under Subpart C alone, 

from the entire petroleum and natural 

gas industry, while requiring only a 

small fraction of total facilities to report. 

For additional information, please refer 

to Greenhouse Gas Emissions from the 

Petroleum and Natural Gas Industry: 

Background TSD (EPA–HQ–OAR–2009– 

0923). For specific information on costs, 

including unamortized first year capital 

expenditures, please refer to section 4 of 

the Economic Impact Analysis. 

Although EPA is proposing an 

emissions threshold of 25,000 mtCO2e 

for all segments of the petroleum and 

natural gas industry, EPA is taking 

comment on whether a 10,000 mtCO2e 

threshold for onshore petroleum and 

natural gas production would be more 

appropriate. 

For onshore petroleum and natural 

gas production, EPA is proposing that 

portable and stationary fuel combustion 

emissions be included in the threshold 

determination due to the large 

percentage of emissions from portable 

equipment in the petroleum and natural 

gas industry. EPA considered lowering 

the threshold to 10,000 mtCO2e and 

excluding portable equipment from the 

threshold determination (and reporting), 

however, data were not available to 

distinguish portable and stationary 

combustion emissions in order to 

evaluate the lower threshold 

considering just stationary combustion 

emissions. 

Secondly, for onshore petroleum and 

natural gas production, EPA is 

proposing that owners or operators 

report at the basin level. EPA is seeking 

comment on owners or operators 

reporting at the field level. Although 

EPA believes that a 25,000 mtCO2e 

threshold is appropriate for the basin 

level approach, as described above, EPA 

seeks comment on whether the 

threshold should be lowered to 10,000 

mtCO2e if reporting were to be at the 

field level. Table W–3 presents the 

emissions and facility coverage for a 

field level definition for onshore 

petroleum and natural gas production. 

TABLE W–3—EMISSIONS COVERAGE AND ENTITIES REPORTING FOR FIELD LEVEL FACILITY DEFINITION

Threshold level 2

Emissions covered Facilities covered 

Metric tons 

CO2e/year Percent Number Percent 

100,000 ............................................................................................................ 99,776,033 38 305 0 

25,000 .............................................................................................................. 144,547,282 55 1,253 2 

10,000 .............................................................................................................. 169,160,462 64 2,846 3 

1,000 ................................................................................................................ 242,621,431 92 39,652 48 

In addition to seeking comment on 

the proposed threshold for onshore 

production, EPA more broadly is 

seeking comment on the selection of the 

threshold for all segments of the 

petroleum and natural gas industry. 

E. Selection of Proposed Monitoring 

Methods 

Many domestic and international 

GHG monitoring guidelines and 

protocols include methodologies for 

estimating emissions from petroleum 

and natural gas operations, including 

the 2006 IPCC Guidelines, U.S. GHG 

Inventory, DOE 1605(b), and corporate 

industry protocols developed by the 

American Petroleum Institute, the 

Interstate Natural Gas Association of 

America, and the American Gas 

Association. The methodologies 

proposed vary by the emissions source 

and the level of accuracy desired in the 

estimation. 

EPA has carefully considered possible 

options to estimate emissions from 

every emission source proposed for 

reporting. EPA has proposed to use the 

most appropriate method taking into 

account both the cost to the reporter as 

well as accuracy of emissions achieved 

through the proposed method. Overall, 

we propose the following types of 

monitoring methods: (1) Direct 

measurement to develop site and 

source-specific emission factors; (2) 

engineering estimation; (3) combination 

of direct measurement and engineering 

estimation; (4) leak detection and use of 

leaker emission factor; and (5) 

population count and population 

emission factors. Table W–4 of this 

preamble provides a list of the 

emissions sources to be reported with 

the corresponding monitoring methods. 

A monitoring method proposed for a 

specific source is to be used across all 

reporting segments of the petroleum and 

gas system. Two exceptions to this are: 

(1) For tanks in onshore natural gas 

transmission facilities that exhibit gas 

bypass from scrubber dump valves, EPA 

is proposing to require direct 

measurement under the proposal, 

whereas in other segments under the 

proposal, the emissions from tanks 

would be required to be estimated using 

E&P Tank simulation software; and (2) 

under the proposal, fugitive emissions 

from onshore petroleum and natural gas 

production and inaccessible to plain 

view (buried or below grade in vaults) 

emissions in gas distribution would 

require estimation using population 

emissions factors as opposed to other 

segments’ fugitive emissions that 

require leak detection and the use of 

leaker emissions factors. Finally, 

offshore petroleum and natural gas 

production platforms would be required 

under the proposal to use methods 

provided by the most recent GOADS 

reporting system. This means that 

Federal Gulf of Mexico platforms would 

report emissions already being 

calculated and reported to MMS as a 

part of the GOADS study and the 

remaining platforms that are not a part 

of the GOADS study (i.e., platforms in 

all state waters and other Federal waters 

outside the Gulf of Mexico) would be 

required to adopt the GOADS 

methodology. 

TABLE W–4. SOURCE SPECIFIC MONITORING METHODS AND EMISSIONS QUANTIFICATION

Emission source Monitoring methods Emissions quantification methods 

Natural Gas Pneumatic Bleed Devices (High or 

Continuous).

Engineering Estimation .................................... Manufacturer device model bleed rate and engineering calculation. 


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TABLE W–4. SOURCE SPECIFIC MONITORING METHODS AND EMISSIONS QUANTIFICATION—Continued 

Emission source Monitoring methods Emissions quantification methods 

Natural Gas Pneumatic Bleed Devices (Low) ... Component Count ............................................ Population emissions factor. 

Natural Gas Driven Pneumatic Pump Venting .. Engineering Estimation .................................... Manufacturer model emissions per unit volume and volume pumped. 

Acid Gas Removal Vent Stacks (CO2 only) ...... Engineering Estimation .................................... Engineering Calculation and flow meters. 

Dehydrator Vent Stacks .................................... Engineering Estimation .................................... GlyCalc simulation software. 

Well Venting for Liquids Unloading ................... (1) Engineering Estimation or (2) Direct Measurement.(1) Field specific emission factor times events 

or (2) Flow metered emission factor times 

events. 

Gas Well Venting during Completions or 

Workovers.

(1) Engineering Estimation, or (2) Direct 

Measurement.

(1) Field specific emission factor times events 

or (2) Flow metered emission factor times 

events. 

Blowdown Vent Stacks ...................................... Engineering Estimation .................................... Equipment specific emission factor and number of events. 

Storage Tanks (Onshore Production and Processing).Engineering Estimation .................................... E&P Tank equipment specific emission factor 

times throughput. 

Storage Tanks (Transmission) .......................... Direct Measurement ......................................... Flow metered emission factor time operating 

hours. 

Well Testing Venting and Flaring ...................... Engineering Estimation .................................... Gas to oil Ratio (GOR); flow rate. 

Associated Gas Venting and Flaring ................. Engineering Estimation .................................... Gas to oil Ratio (GOR); flow rate. 

Flare Stacks ....................................................... (1) Direct Measurement or (2) Engineering Estimation.Engineering Calculation. 

Centrifugal Compressor Wet Seal Oil 

Degassing Vent.

Direct Measurement ......................................... Flow metered equipment specific emission 

factor times operating hours. 

Large Reciprocating Compressor Rod Packing 

Vents.

Direct Measurement ......................................... Flow metered equipment specific emission 

factor times operating hours. 

Large Compressor Blowdown Valve Leak ........ Leak Detection with optical gas imaging instrument.Flow metered equipment specific emission 

factor times operating hours. 

Large Compressor Blowdown Vent (Unit Isolation Valve Leak).Leak Detection with optical gas imaging instrument.Flow metered equipment specific emission 

factor times stand-by depressurized hours. 

Fugitive Sources (Processing, Transmission, 

Underground Storage, LNG Storage, LNG 

Import Export, LDC).

Leak Detection with optical gas imaging instrument.Leaker emission factors times detected leaks. 

Fugitive Sources (Onshore Production, LDC) ... Component Count ............................................ Population Emission Factors times components. 

1. Direct Measurement 

EPA is proposing to require five 

sources in this supplemental proposal to 

directly measure emissions: storage 

tanks (transmission) when scrubber 

dump valves are detected leaking, 

centrifugal compressor wet seal oil 

degassing vents, large reciprocating 

compressor rod packing vents, large 

compressor blowdown vent valve leaks, 

and large compressor blowdown vent 

(unit isolation valve leaks), the latter 

two when leakage is detected. For 

example, storage tanks in the onshore 

natural gas transmission segment 

typically store the condensate (water, 

light hydrocarbons, seal oil) from the 

scrubbing of pipeline quality gas. The 

volume and composition of liquid is 

typically low and variable, respectively, 

in comparison to the volumes and 

composition of hydrocarbon liquids 

stored in the upstream segments of the 

industry. Hence the emissions from 

condensate itself in the transmission 

segment are considered insignificant. 

However, scrubber dump valves 

malfunction or stick-open due to debris 

in the condensate and can remain open 

resulting in natural gas bypass via the 

open dump valve to and through the 

condensate tank, and therefore the use 

of E&P Tanks and other models are not 

applicable to tanks in the transmission 

segment. The only potential option for 

measuring emissions from scrubber 

dump valves is to monitor storage tank 

emissions with a gas imaging camera to 

determine if the emissions do not 

subside and become negligible when 

dump valves close. If the scrubber dump 

valve is stuck and leaking natural gas 

through the tank then the emissions will 

be visibly significant and will not 

subside to inconspicuous volumes. If 

the scrubber dump valve functions 

normally and shuts completely after the 

condensate has been dumped then the 

storage tank, emissions should subside 

and taper off to insignificant quantities. 

If emissions are detected to be 

continuous for a duration of five 

minutes then a one-time measurement 

would be required using a temporary 

meter to establish an equipment specific 

emission factor. 

This proposal is based on the fact that 

the emissions magnitude from these five 

sources are significant enough to 

warrant reporting for the supplemental 

proposed rule and that no credible 

engineering estimation methods or 

emissions factors exist that can 

accurately characterize the emissions. 

There are several public reference 

studies and guidance documents that 

provide emissions factors for these 

sources. However, after close review, 

EPA has determined that these 

emissions factors cannot uniquely 

characterize the emissions specifically 

from individual equipment or a facility. 

For example, the emissions from wet 

seal degassing and rod packing are 

directly correlated to the size of the 

compressor, throughput, and the 

operating time of the compressor in the 

reporting year. Also, in the case of unit 

isolation valves and compressor blow 

down valves the emissions magnitude 

varies depending on operational and 

maintenance practices as valves can 

have excessive leakage, especially when 

a compressor is not in operation. These 

factors do not get accounted for using an 

emissions factor. 

The proposed supplemental rule 

would require that rod packing and 

blowdown valves be measured for 

emissions both in operating as well as 

standby pressurized modes. In addition, 

unit isolation valve leaks would be 

required to be measured at the 


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blowdown vent in the standby depressurized mode. To correctly quantify 

emissions from centrifugal and large 

reciprocating compressors the proposal 

would require that, for each compressor, 

one measurement be taken in each of 

the operational modes that occurs 

during a reporting period: (i) Operating, 

(ii) standby pressurized, and (iii) not 

operating, depressurized. Depending on 

the operational practices each mode 

could have significantly different 

emissions and would need to be 

separately quantified as a part of the 

proposed rule. 

For direct measurement, EPA 

proposes that the following technologies 

be used: high volume samplers, meters 

(such as rotameters, turbine meters, hot 

wire anemometers, and others), and/or 

calibrated bags. EPA recognizes that 

different measurement equipment 

would be required for different source 

emissions measurement depending on 

the configuration of the system. Hence 

the proposed rule provides these 

options for multiple direct measurement 

equipment, but the reporter must 

calibrate and maintain the equipment 

based on either consensus based 

standards or an appropriate method 

specified by the equipment 

manufacturer, as specified in the 

proposed rule. Where a vent emission 

source cannot be accessed on the 

ground or from a fixed platform, the 

reporter has the choice of using a manlift or installing either a permanent or 

temporary vent line access port through 

which a meter can be inserted to 

measure flow or velocity. If emissions 

exceed the maximum range of one 

measurement instrument, the reporter 

would be required to use a different 

instrument option that can measure 

larger magnitude emissions levels. For 

example, if a high volume sampler 

maximum rate is exceeded by an 

emissions source, then emissions would 

be required to be directly measured 

using either calibrated bagging or a 

meter. CH4 and CO2 emissions from the 

emissions stream would be required to 

be calculated using the composition of 

the gas in the process equipment 

(compressor). 

2. Engineering Estimation 

This proposed rule would require two 

main types of engineering calculation 

methods for emissions; (1) volumetric 

calculation method, and (2) engineering 

first principle methods. 

(1) Volumetric Calculation Method 

The volumetric calculation method 

has been proposed for calculating CH4

and CO2 vent emissions from sources 

where the variable in the emissions 

magnitude on an annual basis is the 

number of times the source releases CH4

and CO2 emissions to the atmosphere. In 

addition, the estimation of the total 

volume of emissions is a matter of 

simple arithmetic calculation without 

the need for complex calculations. For 

example, when a compressor is taken 

offline for maintenance, the volume of 

CH4 and CO2 blowdown vent emissions 

that are released is the same during each 

release, is easily calculable, and the 

only variable is the number of times the 

compressor is taken offline and vented. 

(2) Engineering First Principle Methods 

Emissions from sources such as tanks 

and glycol dehydrators can be reliably 

calculated using standard engineering 

first principle methods such as those 

available in E&P Tank and GlyCalc. The 

use of such standard and readily 

available software is a cost-effective way 

to uniformly estimate emissions that are 

representative for the two sources. To 

maintain standardization across 

reporters the proposed rule would 

require the use of E&P Tank for 

estimating the emissions from well-pad 

separator conditions when flashed to 

atmospheric pressure in any 

downstream stock tank, and GlyCalc for 

glycol dehydrators. 

E&P Tank is available for free and 

GlyCalc can be purchased at a small fee. 

Also, these two software models are 

widely used in the industry and the 

operation of the software is well 

understood. Using such software also 

addresses safety concerns that are 

associated with direct measurement 

from the two sources. For example, 

sometimes the temperature of the 

emissions stream for glycol dehydrator 

vent stacks is too high for operators to 

safely measure emissions. EPA seeks 

comment on whether there are 

additional or alternative software 

packages to E&P Tank and GlyCalc that 

should be required to be used to 

calculate emissions. 

In cases where tank emissions do not 

represent equilibrium conditions of the 

liquid in a gas-liquid separator and no 

publicly available data are available on 

vapor bypass direct measurement would 

be required under the proposal. For 

pressurized liquids sent to atmospheric 

storage tanks where tank emissions are 

not expected to be represented by the 

equilibrium conditions of the liquid in 

a gas-liquid separator as calculated by 

the E&P Tank Model, then emissions 

calculated by E&P Tank would be 

multiplied by an empirical factor. 

The supplemental proposed 

rulemaking does not include emissions 

from tanks containing primarily water 

with the exception of transmission 

station condensate tanks where dump 

valve are determined to be bypassing 

gas. Therefore, EPA seeks comments on 

how to quantify emissions from tanks 

storing water without resulting in 

additional reporting burden to the 

facilities. 

For further discussion of these 

software programs and emissions 

calculation methods, refer to 

Greenhouse Gas Emissions from the 

Petroleum and Natural Gas Industry: 

Background TSD (EPA–HQ–OAR–2009– 

0923). 

3. Combination of Direct Measurement 

and Engineering Estimation 

Several sources provide a choice 

between engineering estimation based 

on operating data and direct 

measurement (if meters are already 

installed). For continuous flaring, a onetime direct measurement or engineering 

estimate may be performed in 

conjunction with engineering estimation 

based on operating data that relates to 

the quantity of flared gas. For well 

completion venting and well workover 

venting (each during flowback after 

hydraulic fracturing, the only significant 

well completion emissions), EPA 

explored the possibility of using a meter 

for measuring hydrocarbon gas lost 

during these venting events which may 

last from one to ten days. Some 

companies have reported directly 

measuring these emissions under 

certain circumstances. However, such 

metering could be technically 

challenging, if not impossible, and also 

burdensome given the number of well 

completions and workovers being 

conducted on an annual basis. 

It is important to note, however, that 

no body of data has been identified that 

can be summarized into generally 

applicable emissions factors to 

characterize emissions from these 

sources in each unique field. In fact, the 

emissions factor being used in the 2008 

U.S. GHG Inventory is believed to 

significantly underestimate emissions 

based on industry experience as 

included in the Natural Gas STAR 

Program publicly available information 

(http://www.epa.gov/gasstar/). In 

addition, the 2008 U.S. GHG Inventory 

emissions factor was developed prior to 

the boom in unconventional well 

drilling (1992) and in the absence of any 

field data and does not capture the 

diversity of well completion and 

workover operations or the variance in 

emissions that can be expected from 

different hydrocarbon reservoirs in the 

country. 

As a result, EPA proposes the 

development of a field-specific emission 

factor either by direct measurement of 


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flow rate of hydrocarbons using a meter 

or by an engineering estimation based 

on well choke pressure drop. Given the 

large number of well completions and 

well workovers, EPA proposes that one 

representative well completion and one 

well workover per field horizon be 

developed to characterize emissions per 

day of venting from all other 

completions and workovers in that field 

horizon. The reporter would be required 

to update this factor every two years. 

This would alleviate burden but at the 

same time achieve a reasonable 

characterization of the emissions from 

these two sources. 

5. Use of Leak Detection and Leaking 

Component Emission Factors 

Each segment of the petroleum and 

gas system has a variety of fugitive 

emissions sources that at a source type 

level have low emissions volume, but 

combined together at a segment level 

contribute significantly towards the 

total emissions from petroleum and gas 

systems. EPA considered several 

options for estimating emissions from 

fugitive emissions sources. One option 

considered was to use a population 

count of each fugitive emissions source 

(e.g., source types such as valves, 

connectors, etc.) and multiply it by a 

population emissions factor. This option 

would not account for differences in 

operational and maintenance practices 

among facilities. If population emissions 

factors are used then the fugitive 

emissions from a particular facility will 

remain constant indefinitely until the 

facilities are modified (i.e., change the 

population of equipment) or new factors 

are provided. This approach also will 

not account for fugitive emissions 

reduction measures the industry has 

undertaken in the last few years since 

the population emission factors were 

developed. Facilities with good 

maintenance practices may have 

fugitive emissions lower than the 

population emission factors. As 

described further below, EPA requests 

comment on the use of emission factors 

and ways in which these shortcomings 

may be overcome. 

Another option considered was the 

use of fugitive emissions detection (e.g., 

an infrared camera) and direct 

measurement (e.g., calibrated bags or 

high volume samplers) for fugitive 

sources. This option may be more costeffective when the sources of fugitive 

emissions are in a relatively small 

geographic area such as at a processing 

plant, gas compressor station, or 

distribution gate station. This approach, 

however, could be less cost effective for 

widely dispersed sources (e.g., well 

pads and gathering lines). 

Hence, to overcome these issues, EPA 

proposes conducting fugitive emissions 

detection and then applying leaking 

component (or leak only) emissions 

factors for processing, transmission, 

underground storage, LNG storage, LNG 

import and export terminals, and LDC 

gate stations. The fugitive emissions 

leak detection method does not require 

corresponding direct measurement of 

the fugitive emissions, which is 

significantly more burdensome than 

fugitive emissions detection using the 

most modern optical gas imaging 

instrument detection technology. This 

method is an improvement over the use 

of population emissions factors because 

the factors were developed for leaking 

components and applied only to leaking 

components, leading to a more accurate 

calculation of emissions from each piece 

of equipment. Several commenters to 

the initial proposed rule recommended 

leak detection with an optical gas 

imaging instrument and quantification 

with emission factors. In addition, 

leaking component emissions factors are 

applied only to those emissions sources 

that are determined to be emitting as a 

result of the fugitive emissions detection 

process. 

EPA analyzed new fugitive leak 

studies specifically performed on 

natural gas facilities in processing 

plants and transmission compressor 

stations, as recommended by several 

Subpart W initial proposed rule 

commenters. Leaking component 

emissions factors from these studies 

were compared with other studies (see 

below). EPA found that emission factors 

generated from the Clearstone studies 

related better to methane-rich stream 

fugitives and were more appropriate 

than other emission factors developed 

for highly regulated refinery and 

petrochemical plants on VOC emissions. 

Therefore, EPA is using emissions data 

from the Clearstone studies as the basis 

for the leaker factors proposed in this 

rule. EPA requests comments on the use 

of emission factors from the Clearstone 

studies. For further details see 

Greenhouse Gas Emissions from the 

Petroleum and Natural Gas Industry: 

Background TSD (EPA–HQ–OAR–2009– 

0923). 

Emission References for Petroleum and 

Natural Gas Systems 

API. Compendium of Greenhouse Gas 

Emissions Methodologies for the Oil 

and Gas Industry. American Petroleum 

Institute. Table 4–7, page 4–30. 

February 2004. 

API. Emission Factors for Oil and Gas 

Production Operations. Table 8, page 

10. API Publication Number 4615. 

January 1995. 

EPA. Identification and Evaluation of 

Opportunities to Reduce Methane 

Losses at Four Gas Processing Plants. 

Clearstone Engineering Ltd. June 20, 

2002. http://www.epa.gov/gasstar/ 

documents/four_plants.pdf. 

EPA. Inventory of U.S. Greenhouse 

Gas Emissions and Sinks: 1990–2007. 

Annexes. Tables A–112–A–125. U.S. 

EPA. April 2009. http://epa.gov/ 

climatechange/emissions/downloads09/ 

Annexes.pdf. 

EPA. Lessons Learned: Replacing Wet 

Seals with Dry Seals in Centrifugal 

Compressors. U.S. EPA 2006. http:// 

www.epa.gov/gasstar/documents/ 

ll_wetseals.pdf. 

EPA. Protocol for Equipment Leak 

Emission Estimates. Emission Standards 

Division. U.S. EPA. SOCMI Table 2–7. 

November 1995. http://www.epa.gov/ 

ttn/chief/efdocs/equiplks.pdf. 

GRI. Methane Emissions from the 

Natural Gas Industry. Volume 6. Table 

4–2 and Appendix A, page A–2. June 

1996. http://www.epa.gov/gasstar/ 

documents/emissions_report/ 

6_vented.pdf. 

GRI. Methane Emissions from the 

Natural Gas Industry. Volume 8. Tables 

4–3, 4–6 and 4–24. June 1996. http:// 

www.epa.gov/gasstar/documents/ 

emissions_report/8_equipmentleaks.pdf. 

GRI. Methane Emissions from the 

Natural Gas Industry. Volume 9. Tables 

8–9 and 9–4. June 1996. http:// 

www.epa.gov/gasstar/documents/ 

emissions_report/9_underground.pdf. 

GRI. Methane Emissions from the 

Natural Gas Industry. Volume 10. Table 

7–1. June 1996. http://epa.gov/gasstar/ 

documents/emissions_report/ 

10_metering.pdf. 

ICF. Estimates of Methane Emissions 

from the U.S. Oil Industry. Draft. Page 

13. October 1999. 

Clearstone. Handbook for Estimating 

Methane Emissions from Canadian 

Natural Gas Systems. Clearstone 

Engineering Ltd., Enerco Engineering 

Ltd., and Radian International. Pages 

61–63. May 25, 1998. 

National Gas Machinery Laboratory, 

Kansas State University; Clearstone 

Engineering, Ltd.; Innovative 

Environmental Solutions, Inc. CostEffective Directed Inspection and 

Maintenance Control Opportunities at 

Five Gas Processing Plants and 

Upstream Gathering Compressor 

Stations and Well Sites. For EPA 

Natural Gas STAR Program. March 

2006. 

Clearstone. Handbook for Estimating 

Methane Emissions from Canadian 

Natural Gas Systems. Clearstone 

Engineering Ltd., Enerco Engineering 

Ltd, and Radian International. 2007. 


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EPA considered the use of the three 

major types of emissions detection 

equipment: optical gas imaging 

instruments, IR laser detector 

instruments and Toxic Vapor Analyzers 

(TVA) or Organic Vapor Analyzers 

(OVA). Optical gas imaging instruments 

are able to scan hundreds of source 

types quickly, allowing for the most 

efficient survey of emissions at a broad 

range of facilities. In addition, EPA 

recently adopted detailed performance 

standards for the optical gas imaging 

camera in the Alternative work practice 

for monitoring equipment leaks (AWP) 

(40 CFR part 60 subpart A § 60.18(i)(1) 

and (2)). We recognize that the purchase 

of optical gas imaging instruments can 

be costly, especially for smaller 

facilities. However, EPA believes that 

most facilities will opt for contractors to 

conduct emissions detection once per 

year. As mentioned above, several 

commenters to the initial proposed rule 

recommended leak detection with an 

optical gas imaging instrument in 

accordance with the EPA AWP. Hence, 

the supplemental proposed rule requires 

the use of an optical gas imaging 

instrument compliant with the 

operational requirements of the EPA 

AWP. In contrast to the EPA AWP, 

however, the proposed rule does not 

require multiple surveys per year and 

does not require leak repair. As 

discussed further below, for this 

proposed rule, EPA requires 

comprehensive annual leak detection of 

the fugitive emissions sources specified 

in the proposed rule. The proposed 

supplemental rule does not allow for the 

use of an OVA/TVA. The OVA/TVA 

requires the operator to physically 

access the emissions source with the 

probe and thus is much more time 

intensive than using the optical gas 

imaging instrument. In addition, the 

OVA/TVA range is limited to the reach 

of an operator standing on the ground or 

fixed platform, thus excluding all 

emissions out of reach. However, EPA is 

seeking comments on allowing the 

OVA/TVA to be used as another option 

to the optical imaging camera in this 

proposed rule. 

EPA is aware that the optical gas 

imaging instrument’s ‘‘detection 

sensitivity levels’’ as required by the 

AWP were established from data on 

volatile organic compound (VOC) 

emissions from petroleum refineries and 

chemical plants. The optical gas 

imaging instrument has been used 

extensively to successfully detect 

methane emissions in the petroleum 

and gas industry by petroleum and gas 

companies. A 2006 independent study 

funded through a grant by EPA and 

conducted by Clearstone Engineering, 

was an extensive study of methane 

emissions in gas processing plants and 

upstream gathering compressor stations 

and well sites. Method 21 was 

employed to detect leaks and HiFlow 

samplers were used to determine the 

emissions from those leaks. This study 

surveyed approximately 74,000 

components finding 3,650 leaks (4.9 

percent). Of these leaks, 497 (<1 percent 

of total components) contributed 90 

percent of the total fugitive emissions. 

The smallest of the 497 leaks was 177 

grams per hour, so an optical gas 

imaging instrument should be able to 

adequately image methane leaks since 

the smallest leak was well above the 60 

to 100 gram per hour detection 

sensitivity in Table 1 of the AWP. 

Therefore, for the purposes of this 

reporting rule, EPA determined that an 

optical gas imaging instrument that 

meets the detection sensitivity 

requirements of the AWP for any 

monitoring frequency as specified in 

Table 1 of the AWP, is acceptable for 

use under this proposed rule. Leak 

detection and leaker emission factors 

only apply to emissions sources in 

streams with gas content greater than 10 

percent CH4 plus CO2 by weight. 

Emissions sources in streams with gas 

content less than 10 percent CH4 plus 

CO2 by weight do not need to be 

reported. 

The proposed rule requires that the 

survey for fugitive emissions detection 

be comprehensive. This means that, on 

an annual basis, the entire population of 

fugitive emissions sources proposed for 

reporting in this rule would be surveyed 

at least once. EPA proposes that 

emissions are quantified using leaker 

emissions factors. Under the proposal, if 

a component fugitive emission is 

detected, emissions are assumed to 

occur the entire 365 days in the year. 

EPA is aware that the petroleum and 

natural gas industry is already 

implementing voluntary fugitive 

emissions detection and repair 

programs. Such voluntary programs are 

useful, but pose an accounting challenge 

with respect to emissions reporting for 

this proposed rule. The proposed 

approach does not preclude any owner 

or operator from detecting and repairing 

fugitive emissions prior to quantifying 

emissions for the purposes of reporting 

under this proposed rule. 

To address this issue, EPA 

considered, but did not propose, 

requiring a facility to conduct multiple 

surveys and to report emissions using 

the appropriate leaker factors. Under 

this approach, if a specific emission 

source is found not leaking in the initial 

survey but leaking in subsequent 

surveys, emissions would be quantified 

from the date of the first survey where 

a leak was detected forward through the 

time when the leak is fixed, or the end 

of the year, whichever is first. Similarly, 

if an emissions source is found to be 

leaking in the initial survey, emissions 

would be quantified from the date of 

that survey through to when the leak is 

repaired, or the end of the year, 

whichever is first. Under this approach, 

emissions would reflect leak reductions 

as determined by repairs and follow-up 

detection surveys 

EPA seeks comment on whether this 

alternative approach better estimates 

annual facility emissions without 

resulting in additional reporting burden 

to the facilities. Further, we seek 

comment on whether, if implemented, 

multiple surveys should be optional or 

required for owners or operators. 

6. Use of Population Count and 

Population Emission Factor 

Fugitive emissions detection and use 

of leaking component emissions factors 

are not always cost effective and can be 

burdensome. This is particularly true of 

onshore petroleum and natural gas 

production where the fugitive sources 

are spread out across large geographical 

areas and fugitive emissions are a minor 

contributor to total segment emissions. 

In the distribution segment, pipeline 

fugitive emissions are a large fraction of 

total emissions, but the pipelines are 

buried where leaks are difficult to 

detect. Similarly, metering/regulator 

stations, which are an important source 

of fugitive emissions, are sometimes 

located inside underground vaults that 

are difficult to access. In such scenarios, 

fugitive emissions detection can be 

burdensome. Therefore, for onshore 

petroleum and natural gas production, 

gas gathering pipelines and LDC 

pipelines and M&R stations below grade 

in vaults, the proposed rule requires the 

use of population count of emissions 

sources and population emissions factor 

to estimate fugitive emissions. 

Population count and population 

emission factors only apply to emissions 

sources in streams with gas content 

greater than 10 percent CH4 plus CO2 by 

weight. Emissions sources in streams 

with gas content less than 10 percent 

CH4 plus CO2 by weight do not need to 

be reported. EPA is using emissions data 

from studies listed in the Emission 

References (#2, #4, #5, #7, #8, #9 above) 

as the basis for the population emissions 

factors proposed in this rule. However, 

the API compendium emissions factors 

that we are proposing to use in the 

upstream oil and gas production sector 

may be underestimating emissions. EPA 

seeks comment on how to improve these 


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18624 Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 

factors and/or collect more accurate 

data. 

7. Alternative Monitoring Methods 

Considered 

Before selecting the monitoring 

methods proposed above, we considered 

additional measurement methods. The 

use of Method 21 was considered for 

fugitive emissions detection and 

measurement. Although Toxic Vapor 

Analyzers (TVA) and Organic Vapor 

Analyzers (OVA) were considered they 

were not proposed for fugitive 

emissions detection and quantification. 

Method 21. This is the reference 

method for equipment leak detection 

and repair regulations for volatile 

organic compound (VOC) and 

hazardous air pollutant (HAP) emissions 

under several 40 CFR part 60, 40 CFR 

part 61, 40 CFR part 63, and 40 CFR part 

65 emission standards. Petroleum 

refineries, chemical plants and large gas 

processing plants are required under 

state and federal laws to perform LDAR 

(Leak Detection and Repair) to control 

VOC air pollution emissions. LDAR 

programs require VOC and/or HAP leak 

detection using instruments specified in 

Method 21, and requires repair of leaks 

if the rate is above the leak definitions 

specified within the specific regulation 

(typically between 500 parts per million 

to 10,000 parts per million as read on 

an OVA). Some states and air quality 

districts have lower leak definitions 

than the Federal standards. LDAR 

programs require facilities to conduct 

multiple surveys per year: either 

following equipment-specific 

frequencies using VOC monitoring 

instruments, or bi-monthly, semiquarterly or monthly using an optical 

gas imaging instrument, frequency 

depending on the sensitivity detection 

of the instrument. While LDAR 

programs do not require quantification, 

state inventories of air emissions use 

this LDAR leak detection data with 

‘‘leaker’’ factors developed by the 

Synthetic Organic Chemicals 

Manufacturing Industry (SOCMI) to 

estimate the quantity of VOC emissions. 

These factors were developed from 

petroleum refinery and petrochemical 

plant data using Method 21. SOCMI 

factors adjusted for methane content are 

considerably lower than the methane 

factors proposed in this rule, which 

were developed from more recent 

studies of gas processing plants and 

compressor stations. 

The Federal LDAR program recently 

adopted an alternative work practice 

that allows use of optical gas imaging 

instruments in place of the VOC 

monitoring instrument specified in 

Method 21. In a similar vein, this rule 

proposes the use of optical gas imaging 

instruments to detect leaks once per 

year, and has developed leaker factors 

specific to methane from several recent 

studies quantifying component leaks in 

petroleum and gas facilities. While this 

rule proposes a similar approach to 

Method 21, given that this is a reporting 

rule for collecting annual GHG 

emissions, there are several key 

differences: the proposed annual 

reporting rule is focused on gathering 

fugitive and vented CO2 and CH4

emissions, does not require multiple 

surveys per year, and does not allow 

measurement using an OVA/TVA for 

the reasons cited above. Optical gas 

imaging instruments were found to be 

more appropriate for leak detection for 

the proposed supplemental rule as these 

instruments are able to scan hundreds of 

source components quickly, including 

components out of reach for an OVA/ 

TVA. 

Mass Balance for Quantification. 

Except in one case, EPA considered, but 

decided not to propose, the use of a 

mass balance approach for quantifying 

emissions across an entire facility. This 

approach would take into account the 

volume of gas entering a facility and the 

amount exiting the facility, with the 

difference assumed to be emitted to the 

atmosphere. This is most often 

discussed for emissions estimation from 

the transportation segment of the 

industry. However, for pipeline 

transportation, the mass balance is often 

not recommended because of the 

uncertainties surrounding meter 

readings, the highly variable line pack 

of high pressure gas and the large 

volumes of throughput relative to 

emissions. 

EPA is proposing this approach in the 

case of one emission source—acid gas 

recovery units. Typically, the natural 

gas volumes and compositions are 

measured both at the inlet and outlet of 

the acid gas recovery units as it is 

required to ensure that natural gas meets 

transmission system pipeline 

specifications. Hence, it is considered 

sufficiently feasible to use the mass 

balance approach for this source. For all 

other facilities and sources, the accuracy 

required in volume measurements will 

be a significant added burden in 

addition to being unreliable in many 

cases. 

F. Selection of Procedures for Estimating 

Missing Data 

The proposal requires data collection 

for a single source a minimum of once 

a year. If data are lost or an error occurs 

during emissions detection and/or 

measurement or calculation, the 

operator would be required to carry out 

the detection, direct measurement, and/ 

or calculation a second time to obtain 

the relevant data point(s) as soon as the 

missing data are discovered. If this falls 

outside of the reporting year (e.g. 

between the end of the reporting year 

and the date when the emissions must 

be reported) the operator would be 

required to perform the necessary data 

development and report the results for 

the previous year. This prior year’s lost 

data replacement could not be used as 

the one-time data collection for the 

current year. Where missing data 

procedures are used for the previous 

year, at least 30 days would be required 

to separate emissions estimation and/or 

measurements for the previous year and 

emissions estimation and/or 

measurements for the current year of 

data collection in order to better 

represent emissions estimates for 

different years. Similarly, engineering 

estimates would account for relevant 

source counts and frequency from the 

previous reporting period. 

G. Selection of Data Reporting 

Requirements 

EPA proposes that emissions from the 

petroleum and natural gas industry be 

reported on an annual basis. The 

reporting should be by the owner or 

operator of the facility as defined in the 

supplemental rule. Emissions from each 

source type at the facility would be 

required to be aggregated for reporting, 

with a few exceptions for field level 

reporting (e.g., well completions and 

well workovers). For other equipment, 

unit-level reporting would not be 

required. For example, the owner or 

operator with multiple reciprocating 

compressors in an onshore production 

basin would be required to report 

emissions collectively from all rod 

packings on all cylinders from all 

compressors for all fields in that basin 

as specified in this proposed 

rulemaking. Generally, EPA has 

proposed that onshore production be 

reported at the basin level, as opposed 

to the unit or field level, to minimize 

reporting burden. EPA notes that in a 

concurrent proposed rulemaking for 

facilities that conduct CO2 injection or 

geologic sequestration (subpart RR), the 

term ‘‘facility’’ is defined at a more 

disaggregated level, specifically as a 

‘‘well or group of wells.’’ EPA seeks 

comment on the use of more 

disaggregated reporting options for 

subpart W. 

Emissions from all sources proposed 

for monitoring, whether in operating 

condition or on standby, would have to 

be reported. Any emissions resulting 

from standby compressor sources would 


srobinson on DSKHWCL6B1PROD with PROPOSALS3
Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 18625 

be separately identified from the 

aggregate emissions. 

The owner or operator would be 

required to report the following 

information to EPA as a part of the 

annual emissions reporting: fugitive, 

vented and flare combustion emissions 

monitored at an aggregate source level 

(unless specified otherwise), emissions 

from standby sources; and activity data 

for each aggregate source type level. 

Owners or operators of natural gas 

distribution facilities would report 

emissions at the individual station level. 

Additional data are proposed to be 

reported to support verification: 

Engineering estimate of total component 

count; total number of compressors and 

average operating hours per year in each 

mode of operation for compressors, if 

applicable; minimum, maximum and 

average throughput per year; and 

specification of the type of any control 

device used, including flares. For 

offshore petroleum and natural gas 

production facilities, the number of 

connected wells, and whether they are 

producing oil, gas, or both is proposed 

to be reported. For compressors 

specifically, EPA proposes that the total 

number of compressors of each type 

(reciprocating, centrifugal with dry seals 

and centrifugal with wet seals) and 

average operating hours per year be 

reported. 

A full list of data proposed to be 

reported is included in proposed 40 

CFR part 98, subparts A and W. 

H. Selection of Records That Must Be 

Retained 

The owner or operator shall retain 

relevant information associated with the 

monitoring and reporting of emissions 

to EPA for three years as follows: 

Throughput of the facility when the 

emissions direct measurement was 

conducted; date(s) of measurement, 

detection and measurement instruments 

used, if any; and results of the emissions 

detection survey, including a video 

record of the leak survey. 

A full list of records proposed to be 

retained is included in proposed 40 CFR 

part 98, subparts A and W. 

III. Economic Impacts of the Proposed 

Rule 

This section of the preamble examines 

the costs and economic impacts of this 

proposed supplemental rule, including 

the estimated costs and benefits of the 

rule, and the estimated economic 

impacts of the rule on affected entities, 

including estimated impacts on small 

entities. Complete details of the 

economic impacts of the final rule can 

be found in the text of the Economic 

Impact Analysis for the Mandatory 

Reporting of Greenhouse Gas Emissions 

under Subpart W Supplemental Rule 

(EPA–HQ–OAR–2009–0923). In brief, 

all equipment and labor activities for 

complying with each emissions estimate 

in the rule were analyzed by technical 

experts with relevant industry 

experience. The estimated labor hours 

and labor categories were applied to 

each industry segment, in some cases 

proportioned to small, medium and 

large facilities where such variation 

exists, to quantify the total labor hours, 

multiplied by Government statistics on 

labor rates, arriving at the total labor 

and equipment costs for the estimated 

numbers of sources. Administrative 

costs for reviewing the reporting rules, 

training personnel, documenting 

emissions data and emissions estimates, 

approving the submission to the EPA, 

submitting reports and maintaining 

records were included for each 

reporting company. These total bottomup cost estimates were divided by the 

emissions captured to arrive at the 

dollar per metric ton, and divided by 

the number of reporting entities to 

arrive at average costs per entity. The 

methods proposed by EPA are a balance 

between minimizing these costs, 

maximizing emissions coverage and 

maximizing quality of emissions 

estimates. The cost to affected parties on 

a dollar per metric ton has been reduced 

by greater than 50 percent when 

compared to the initial petroleum and 

natural gas proposal. To achieve this 

cost reduction, EPA significantly 

modified the rule to rely significantly 

less on direct measurement and more on 

engineering estimates, leaker factors and 

emissions factors. Table W–5 and Table 

W–6 compare the first year and 

subsequent year costs, respectively, to 

reporters for reporting fugitive and 

vented emissions based on the reporting 

requirements proposed under the initial 

proposal as compared to the new 

supplemental proposed rule. 

TABLE W–5—ESTIMATED FIRST YEAR COST FOR REPORTING FUGITIVE AND VENTED EMISSIONS FOR PETROLEUM AND

NATURAL GAS SYSTEMS, MMTCO2E 

Segment 

Initial proposed rule1 New supplemental proposed 

rulemaking 

Cost 

($million) 

Cost per tonne 

($/tonne) Cost 

($million) 

Cost per tonne 

($/tonne) 

Original six segments ...................................................................................... $32.5 $0.38 $26.7 $0.28 

Onshore Production ......................................................................................... NA NA 27.7 0.18 

Natural Gas Distribution .................................................................................. NA NA 1.6 0.07 

Total Segments ........................................................................................ 32.5 0.38 56.0 0.21 

1The costs for the initial proposed rule, shown here, reflect the in-house monitoring option. Costs for the alternative contractor monitoring option can be found in Docket EPA–HQ–OAR–2008–0508–0138. 

TABLE W–6—ESTIMATED SUBSEQUENT YEAR COST FOR REPORTING FUGITIVE AND VENTED EMISSIONS FOR PETROLEUM

AND NATURAL GAS SYSTEMS, MMTCO2E 

Segment 

Initial proposed rule New supplemental proposed 

rulemaking 

Cost 

($million) 

Cost per tonne 

($/tonne) Cost 

($million) 

Cost per tonne 

($/tonne) 

Original six segments ...................................................................................... $28.1 $0.33 11.8 $0.13 

Onshore Production ......................................................................................... NA NA 8.6 0.06 

Natural Gas Distribution .................................................................................. NA NA 1.0 0.04 


srobinson on DSKHWCL6B1PROD with PROPOSALS3
18626 Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 

TABLE W–6—ESTIMATED SUBSEQUENT YEAR COST FOR REPORTING FUGITIVE AND VENTED EMISSIONS FOR PETROLEUM

AND NATURAL GAS SYSTEMS, MMTCO2E—Continued 

Segment 

Initial proposed rule New supplemental proposed 

rulemaking 

Cost 

($million) 

Cost per tonne 

($/tonne) Cost 

($million) 

Cost per tonne 

($/tonne) 

Total Segments ........................................................................................ $28.1 $0.33 21.4 0.08 

1Subsequent year in the initial proposed rule was defined as Year 2 whereas in the supplemental proposed rule it is defined as the average of 

Years 2, 3, and 4. 

A. How were compliance costs 

estimated? 

1. Summary of EPA’s Consideration of 

Comments Received on the Initial 

Proposal 

A majority of the comments received 

on the compliance costs of the fugitive 

emissions reporting rule focused on 

facility level costs for detection and 

measurement of emissions. Commenters 

noted that costs estimated for certain 

petroleum and gas industry segments 

ignored available data on average leak 

factors. Some who commented 

specifically referred to government 

programs that gather similar, or in the 

case of offshore petroleum and gas 

production in the Gulf of Mexico 

Federal waters, some of the same data 

as required under Subpart W. Others 

who commented noted that Subpart W 

had higher estimated compliance costs 

than other sectors for much smaller 

GHG emissions. 

EPA recognizes that the costs 

presented for some petroleum and gas 

industry segments in the initial proposal 

were relatively high for smaller 

emissions quantified than other 

industry sectors. EPA also recognizes 

that for many fugitive and vented 

emissions sources, new data exist on 

component emission factors, and long 

established data may be justified for 

smaller, inaccessible to plain view or 

more burdensome to identify emission 

sources. Furthermore, EPA recognizes 

that other government programs gather 

similar or the same data as proposed by 

this rule. 

This proposed supplemental rule 

incorporates a number of different 

methodologies to provide improved 

emissions coverage at a lower cost 

burden to affected facilities. The 

approach used in determining the 

appropriate methodology for the 

supplemental was to minimize the use 

of direct measurement of emissions 

(which results in a higher cost burden 

to affected facilities) except for the most 

significant emissions sources where 

other options are not available, and to 

use engineering estimates, emissions 

modeling software, and leak detection 

and publicly available emission factors 

for most vented and fugitive sources. 

For smaller fugitive and inaccessible to 

plain view (i.e. buried or below grade in 

vaults) sources, component count and 

population emissions factors are 

proposed. In the case of Offshore 

platforms, EPA is recommending that 

emissions identified under the Minerals 

Management Services (MMS) GOADS 

(Gulfwide Offshore Activities Data 

System) be used for reporting, and the 

GOADS process be extended to 

platforms in other Federal regions (i.e., 

California and Alaska) and all State 

waters. These alternative methodologies 

will provide similar or better coverage 

of vented and fugitive methane and 

carbon dioxide emissions in the 

petroleum and gas industry, while 

significantly reducing industry burden. 

As described in the next section, EPA 

collected and evaluated cost data from 

multiple sources, and weighed the 

analysis prepared at initial proposal 

against the input received through 

public comments. In any analysis of this 

type, there will be variations in costs 

among facilities, and after thoroughly 

reviewing the available information, we 

have concluded that the costs developed 

for this supplemental proposed rule in 

each petroleum and gas industry 

segment appropriately reflects a 

‘‘representative facility’’ in those 

segments. 

2. Summary of Method Used To 

Estimate Compliance Costs 

EPA estimated costs of complying 

with the rule for reporting fugitive and 

vented GHG emissions in each affected 

petroleum and gas industry facility, as 

well as emissions from stationary 

combustion sources at petroleum and 

gas industry facilities (for threshold and 

burden analysis only; stationary 

combustion is reported under Subpart 

C). This supplemental rulemaking 

proposes methodologies for reporting 

fugitive and vented emissions from oil 

and gas facilities. Once triggering the 

proposed rule, all of these facilities 

would also have to report emissions 

from stationary combustion. The costs 

of compliance for this proposed rule 

includes the costs associated with 

calculating and reporting fugitive and 

vented emissions, as well as the costs of 

any incremental combustion-related 

emissions that would be required to be 

reported by facilities (i.e., combustion 

emissions that were not already 

required to be reported under the final 

MRR). The representative year of the 

analysis is 2006 and all annual costs 

were estimated using the 2006 

population of emitting sources. EPA 

used available industry and EPA data to 

characterize conditions at affected 

sources. Incremental monitoring, 

recordkeeping, and reporting activities 

were then identified for each type of 

facility and the associated costs were 

estimated. 

The costs of complying with the rule 

will vary from one petroleum and gas 

industry segment and facility to another, 

depending on the types of emissions, 

the number of affected sources at the 

facility, existing monitoring, 

recordkeeping, and reporting activities 

at the facility, etc. The costs include 

labor costs for developing a plan, setting 

up records, collecting field data, 

performing monitoring, inputting field 

data into engineering models, 

recordkeeping, and reporting activities 

necessary to comply with the rule. For 

some facilities, costs include 

expenditures related to monitoring, 

recording, and reporting both process 

emissions of GHGs and emissions from 

stationary combustion. For other 

facilities (e.g., LDCs), the only emissions 

of GHGs are process emissions. EPA’s 

estimated costs of compliance are 

discussed in greater detail below: 

Labor Costs. The costs of complying 

with and administering this rule include 

time of managers, technical, operational 

and administrative staff in the private 

sector. Staff hours are estimated for 

activities, including: 

• Developing a plan: reporting entity 

management and technical staff hours to 

applicability to the rule, organize 

indoctrination of rule requirements, 

identify staffing assignments, train staff, 

schedule activities as required below. 


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• Setting up records: technical and 

field staff hours to develop data 

collection sheets and analytical model 

equations or linkages to input data into 

standardized models 

• Collecting field data: technical and 

field staff hours to collect necessary sitespecific data and input that data into the 

analytical input tables. 

• Monitoring: staff hours to procure, 

install, operate and maintain emissions 

monitoring equipment, instruments and 

engineering analysis systems. 

• Engineering models: technical staff 

hours to link and execute engineering 

emissions estimation models and 

analytical procedures and to organize 

output data as required for reporting 

emissions. 

• Record keeping: staff hours required 

to organize, file and secure critical data 

and emissions quantification results as 

required for reporting and for 

documenting determinations of facilities 

exceeding and not exceeding reporting 

thresholds. 

• Reporting: management and staff 

hours to organize data, perform quality 

assurance/quality control, inform key 

management personnel, and reporting it 

to EPA through electronic systems. 

Staff activities and associated labor 

costs will vary from facility to facility 

and potentially vary over time where 

first year start-up costs are more 

significant and where site-specific 

emissions factors are developed every 

two or three years. Thus, cost estimates 

are developed for start-up and first-time 

reporting, and subsequent reporting. 

Wage rates to monetize staff time are 

obtained from the Bureau of Labor 

Statistics (BLS). 

Equipment Costs. Equipment costs 

include both the initial purchase price 

of monitoring equipment and any 

facility/process modification that may 

be required for installation and/or use of 

monitoring equipment. For example, the 

cost estimation method for large 

compressor seal emissions includes 

both purchase of a flow measurement 

instrument and installation of a 

measurement port in the vent piping 

where the end of the vent is 

inaccessible. Based on expert judgment, 

the engineering costs analyses 

annualized capital equipment costs with 

appropriate lifetime and interest rate 

assumptions. Cost recovery periods and 

interest rates vary by industry, but 

typically, one-time capital costs are 

amortized over a 10-year cost recovery 

period at a rate of seven percent. 

B. What are the costs of the proposed 

rule? 

1. Summary of Costs 

For the cost analysis, EPA gathered 

existing data from EPA studies and 

publications, industry trade associations 

and publicly available data sources (e.g., 

labor rates from the BLS) to characterize 

the processes, sources, sectors, facilities, 

and companies/entities affected. EPA 

also considered cost data submitted in 

public comments on the proposed rule. 

Costs were estimated on a per entity 

basis and then weighted by the number 

of entities affected at the 25,000 metric 

tons CO2e threshold. 

To develop the costs for the rule, EPA 

estimated the number of affected 

facilities in each source category, the 

number and types of process equipment 

at each facility, the number and types of 

processes that emit GHGs, process 

inputs and outputs (especially for 

monitoring procedures that involve a 

carbon mass balance), and the 

measurements that are already being 

made for reasons not associated with the 

rule (to allow only the incremental costs 

to be estimated). Many of the affected 

source categories, especially those that 

are the largest emitters of GHGs (e.g., 

glycol dehydrators, petroleum stock 

tanks, gas processing plants) are subject 

to national emission standards and we 

use data generated in the development 

of these standards to estimate the 

number of sources affected by the 

proposed reporting rule. 

Other components of the cost analysis 

included estimates of labor hours to 

perform specific activities, cost of labor, 

and cost of monitoring equipment. 

Estimates of labor hours were based on 

previous analyses of the costs of 

monitoring, reporting, and 

recordkeeping for other rules; 

information from the industry 

characterization on the number of units 

or process inputs and outputs to be 

monitored; and engineering judgment 

by industry and EPA industry experts 

and engineers. Labor costs were taken 

from the BLS and adjusted to account 

for overhead. Monitoring costs were 

generally based on cost algorithms or 

approaches that had been previously 

developed, reviewed, accepted as 

adequate, and used specifically to 

estimate the costs associated with 

various types of measurements and 

monitoring. 

A detailed engineering analysis was 

conducted for each petroleum and gas 

industry segment of this proposed rule 

to develop unique unit costs. This 

analysis is documented in the Economic 

Impact Analysis for the Mandatory 

Reporting of Greenhouse Gas Emissions 

under Subpart W Supplemental Rule 

(EPA–HQ–OAR–2009–0923). The 

Greenhouse Gas Emissions from the 

Petroleum and Natural Gas Industry: 

Background TSD (EPA–HQ–OAR–2009– 

0923) provides a discussion of the 

applicable engineering estimating and 

measurement technologies and any 

existing programs and practices. 

Incremental combustion-related 

emissions that would be required to be 

reported by facilities (as noted above) 

were estimated using Tier 1 factors from 

Subpart C of the Final MRR. Section 4 

of the Economic Impact Analysis for the 

proposed rule contains a description of 

the engineering cost analysis. 

Table W–7 of this preamble presents: 

the emissions covered under this 

proposed supplemental rule, the first 

year total costs and the first year cost 

per ton for process and combustion 

emissions, and these values for the 

subsequent years. EPA estimates that 

the total cost for process emissions in 

the first year is $56.0 million, and the 

total national annualized cost for 

subsequent years is $21.4 million 

(2006$). Of these costs, roughly 49.5 

percent fall upon the onshore 

production segment in the first year, 

while 34.5 percent fall upon the gas 

transmission segment. Offshore 

production, which is largely covered by 

the MMS GOADS study data, is 

estimated to incur approximately 0.5 

percent of costs every three or four 

years; other segments incurring 

relatively large shares of costs are gas 

processing (12.5 percent) and local 

distribution companies (3 percent). The 

reporting of incremental combustion 

related emission for all segments of the 

petroleum and natural gas industry are 

estimated to cost $3.9 million in both 

the first and subsequent years. 

The threshold, in large part, 

determines the number of entities 

required to report GHG emissions and 

hence the costs of the rule. The number 

of entities excluded increases with 

higher thresholds. Table W–8 of this 

preamble provides the cost-effectiveness 

analysis for various thresholds 

examined. Two metrics are used to 

evaluate the cost-effectiveness of the 

emissions threshold. The first is the 

average cost per metric ton of emissions 

reported ($/metric ton CO2e). The 

second metric for evaluating the 

threshold option is the incremental cost 

of reporting emissions. The incremental 

cost is calculated as the additional 

(incremental) cost per metric ton 

starting with the least stringent option 

and moving successively from one 

threshold option to the next. For more 

information about the first year capital 

costs (unamortized), project lifetime and 


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18628 Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 

the amortized (annualized) costs for 

each petroleum and gas industry 

segment please refer to section 4 of the 

Economic Analysis for the proposed 

rule. Not all segments require capital 

expenditures but those that do are 

clearly documented in the Economic 

Impact Analysis for the proposed rule. 

TABLE W–7—NATIONAL COST ESTIMATES FOR PETROLEUM AND NATURAL GAS SYSTEMS

[2006$] 

Subpart W—petroleum and natural gas 

systems NAICS 

First year Subsequent years 

$million1

Million 

MtCO2e $/ton 

$million Million 

MtCO2e $/ton 

2006 2006 

Fugitive and Vented Emissions ............... 211, 486 $56 272.0 $0.21 $21.4 272.0 $0.08 

Combustion Emissions ............................ .................... 3.9 79.1 0.05 3.9 79.1 0.05 

Total Private Sector Emissions ........ .................... 59.9 351.1 0.17 25.3 351.1 0.07 

TABLE W–8—THRESHOLD COST-EFFECTIVENESS ANALYSIS

[Subsequent year, 2006$] 

Threshold 

(metric tons CO2e) 

Facilities required 

to report 

Total costs 

(million $2006) 

Downstream emissions reported 

(MtCO2e/year) 

Percentage of 

total downstream 

emissions reported 

Average reporting 

cost 

($/ton) 

Incremental cost 

($/metric ton) 1

100,000 1,143 $13.66 273 64 $0.05 $0.05 

25,000 3,037 25.30 351 83 0.08 0.13 

10,000 4,884 38.62 380 90 0.10 0.23 

1,000 15,057 97.18 415 98 0.23 0.46 

1 Cost per metric ton relative to the selected option. 

C. What are the economic impacts of the 

proposed rule? 

1. Summary of Economic Impacts 

EPA prepared an economic impact 

analysis to evaluate the impacts of the 

rule on affected small to large reporting 

entities. In evaluating the various 

reporting options considered, EPA 

conducted a cost-effectiveness analysis, 

comparing the cost per metric ton of 

GHG emissions across reporting options. 

EPA used this information to identify 

the preferred options described in 

today’s proposed rule. 

To estimate the economic impacts of 

the rule, EPA first conducted a 

screening assessment, comparing the 

estimated total annualized compliance 

costs for the petroleum and gas 

industry, where industry is defined in 

terms of North American Industry 

Classification System (NAICS) code, 

with industry average revenues. Overall 

national costs of the rule are significant 

because there are a large number of 

affected entities, but per-entity costs are 

low due to large coverage of emissions 

from these entities. Average cost-to-sales 

ratios for establishments in the affected 

NAICS codes for all segments is less 

than 1 percent, except in the 1–20 

employee range for the onshore 

petroleum and natural gas segment. 

These low average cost-to-sales ratios 

indicate that the proposed rule is 

unlikely to result in significant changes 

in firms’ production decisions or other 

behavioral changes, and thus unlikely to 

result in significant changes in prices or 

quantities in affected markets. Thus, 

EPA followed its Guidelines for 

Preparing Economic Analyses (EPA, 

2002, p. 124–125) and used the 

engineering cost estimates to measure 

the social cost of the rule, rather than 

modeling market responses and using 

the resulting measures of social cost. 

Table W–9 of this preamble summarizes 

cost-to-sales ratios for affected 

industries. 

TABLE W–9—ESTIMATED COST-TO-SALES RATIOS FOR AFFECTED ENTITIES

[Year 1] 

NAICS NAICS description 

Average cost per 

entity 

($1,000/entity) 

Average entity 

cost-to-sales 

ratio1

211 .................... Crude Petroleum and Natural Gas Extraction .................................................................. $24 0.11% 

486210 .............. Pipeline Transportation of Natural Gas ............................................................................ 18 0.10% 

221210 .............. Natural Gas Distribution ................................................................................................... 11 0.05% 

1This ratio reflects first year costs. Subsequent year costs will be slightly lower because they do not include initial start-up activities. 


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9EPA’s RFA guidance for rule writers suggests 

the ‘‘sales’’ test continues to be the preferred 

quantitative metric for economic impact screening 

analysis. 

D. What are the impacts of the proposed 

rule on small businesses? 

1. Summary of Impacts on Small 

Businesses 

As required by the RFA and Small 

Business Regulatory Enforcement and 

Fairness ACT (SBREFA), EPA assessed 

the potential impacts of the rule on 

small entities (small businesses, 

governments, and non-profit 

organizations). (See Section IV.C of this 

preamble for definitions of small 

entities.) 

EPA has determined the selected 

threshold maximizes the rule coverage 

with 83 percent of U.S. GHG emissions 

from the industry segments reported by 

approximately 3,037 reporters, while 

keeping reporting burden to a 

minimum. Furthermore, many industry 

stakeholders that EPA met with 

expressed support for a 25,000 metric 

ton CO2e threshold because it 

sufficiently captures the majority of 

GHG emissions in the U.S., while 

excluding most of the smaller facilities 

and sources. We received many 

comments related to monitoring and 

reporting requirements in specific 

source categories, and made many 

changes in response to reduce burden 

on reporters. For information on these 

issues, refer to the discussion of each 

segment in this preamble. 

EPA conducted a screening 

assessment comparing compliance costs 

to onshore petroleum and natural gas 

production specific receipts data for 

establishments owned by small 

businesses. This ratio constitutes a 

‘‘sales’’ test that computes the 

annualized compliance costs of this rule 

as a percentage of sales and determines 

whether the ratio exceeds one percent.9

The cost-to-sales ratios were constructed 

at the establishment level (average 

reporting program costs per 

establishment/average establishment 

receipts) for several business size 

ranges. This allowed EPA to account for 

receipt differences between 

establishments owned by large and 

small businesses and differences in 

small business definitions across 

affected industries. The results of the 

screening assessment are shown in 

Table W–10 of this preamble. 

TABLE W–10.—ESTIMATED COST-TO-SALES RATIOS FOR FIRST YEAR COSTS BY INDUSTRY AND ENTERPRISE SIZEA

Industry NAICS 

NAICS 

Description 

SBA Size 

Standard 

(effective 

March 11, 

2008) 

Average 

cost per 

entity 

($1,000/ 

entity) 

All enterprises 

Owned by enterprises with: 

<20 employeesf

20 to 99 

employees 

100 to 

499 employees 

500 to 

749 employees 

<500 employees 

750 to 

999 employees 

1,000 to 

1,499 

employees 

Onshore petroleum 

and natural gas 

production; offshore 

petroleum and natural gas production; 

LNG storage; LNG 

import and export.

211 Crude Petroleum 

and Natural Gas 

Extraction.

500 employees.$24 0.11% 1.83% 0.16% 0.07% 0.03% 0.65% 0.04% 0.03% 

Onshore natural gas 

processing; onshore natural gas 

transmission; underground natural 

gas storage.

486210 Pipeline 

Transportation 

of Natural Gas.

7.5 million 

dollars.

18 0.10 0.14 0.47 b 0.28 b ................ 0.12 ................ ................

Natural gas distribution.221210 Natural 

Gas 

Distribution.

7.5 million 

dollars.

11 0.05 0.22 0.02 0.05 0.09 0.06 0.02 0.02 

1The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of 

all associated establishments. 

Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, we assume in this analysis that the enterprise definition above is consistent with the concept of ultimate parent company that is typically used for SBREFA screening analyses. 2The Census Bureau has missing data ranges for this employee range. Hence the receipts are an underestimate of the true value. Therefore, the cost-to-sales 

ratio is a conservative estimate. 

As shown, the cost-to-sales ratios are 

less than one percent for establishments 

owned by small businesses that EPA 

considers most likely to be covered by 

the reporting program, except the ratio 

for 1–20 employee range for crude 

petroleum and natural gas extraction, 

which is greater than 1 percent but less 

than 2 percent. The petroleum and 

natural gas industry has a large number 

of enterprises, the majority of them in 

the 1–20 employee range. However, a 

large fraction of production comes from 

large corporations and not those with 

less than 20 employee enterprises. The 

smaller enterprises in most cases deal 

with very small operations (such as a 

single family owning a few production 

wells) that are unlikely to cross even the 

25,000 metric tons CO2e threshold 

considered for the rule. An exception to 

such a scenario is a small (less than 20 

employee) enterprise owning large 

operations but conducting nearly all of 

its operations through contractors. This 

is not an uncommon practice in the 

onshore petroleum and natural gas 

production segment. Such enterprises, 

however, are a very small group among 

the over 19,000 enterprises in the less 

than 20 employee category and EPA 

proposes to cover them in the rule. 

EPA took a conservative approach 

with the model entity analysis. 

Although the appropriate SBA size 

definition should be applied at the 

parent company (enterprise) level, data 

limitations allowed us only to compute 

and compare ratios for a model 

establishment within several enterprise 

size ranges. 

Although this rule will not have a 

significant economic impact on a 

substantial number of small entities, the 

Agency nonetheless tried to reduce the 

impact of this rule on small entities, 

including seeking input from a wide 

range of private- and public-sector 


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18630 Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 

10Although CBI determinations are usually made 

on a case-by-case basis, EPA has issued guidance 

in an earlier Federal Register notice on what 

constitutes emissions data that cannot be 

considered CBI (956 FR 7042–7043, February 21, 

1991). As discussed in Section II.R of the Final 

MRR preamble, EPA is initiating a separate notice 

and comment process to make CBI determinations 

for the data collected under this rulemaking. EPA 

intends to issue this notice in early 2010, and will 

include in the notice the data proposed for 

collection in this rulemaking. 

stakeholders. When developing the rule, 

the Agency took special steps to ensure 

that the burdens imposed on small 

entities were minimal. The Agency 

conducted several meetings with 

industry trade associations to discuss 

regulatory options and the 

corresponding burden on industry, such 

as recordkeeping and reporting. The 

Agency investigated alternative 

thresholds and analyzed the marginal 

costs associated with requiring smaller 

entities with lower emissions to report. 

The Agency also recommended a hybrid 

method for reporting, which provides 

flexibility to entities and helps 

minimize reporting costs. 

E. What are the benefits of the proposed 

rule for society? 

EPA examined the potential benefits 

of the proposed GHG reporting rule for 

petroleum and natural gas systems. The 

benefits of a reporting system are based 

on their relevance to policy making, 

transparency issues, and market 

efficiency. Benefits are very difficult to 

quantify and monetize. Instead of a 

quantitative analysis of the benefits, 

EPA conducted a systematic literature 

review of existing studies including 

government, consulting, and scholarly 

reports. 

A mandatory reporting system for 

petroleum and natural gas systems will 

benefit the public by increased 

transparency of facility emissions data. 

Transparent, public data on emissions 

allows for accountability of polluters to 

the public stakeholders who bear the 

cost of the pollution. Citizens, 

community groups, and labor unions 

have made use of data from Pollutant 

Release and Transfer Registers to 

negotiate directly with polluters to 

lower emissions, circumventing greater 

government regulation. Publicly 

available emissions data also will allow 

individuals to alter their consumption 

habits based on the GHG emissions of 

producers. 

The greatest benefit of mandatory 

reporting of petroleum and natural gas 

systems GHG emissions to government 

will be realized in developing future 

GHG policies. For example, in the 

European Union’s Emissions Trading 

System, a lack of accurate monitoring at 

the facility level before establishing CO2

allowance permits resulted in allocation 

of permits for emissions levels an 

average of 15 percent above actual levels 

in every country except the United 

Kingdom. 

As the primary constituent of natural 

gas, methane is also an important energy 

source. As a result, methane emissions 

reductions can provide significant 

economic and environmental benefits. 

EPA has been working in collaboration 

with oil and natural companies in the 

U.S. as part of the Natural Gas STAR 

Program since 1993. Through this 

collaborative partnership program, EPA 

has identified over 120 proven, cost 

effective technologies and practices to 

reduce methane emissions across 

operations in all of the major industry 

sectors—production, gathering and 

processing, transmission, and 

distribution. The proposed reporting 

rule will increase knowledge of the 

location and magnitude of significant 

methane emissions sources in the oil 

and gas industry which can result in 

cross-cutting benefits on domestic 

energy supply, industrial efficiency and 

safety, and revenue generation. 

Benefits to industry of GHG emissions 

monitoring include the value of having 

independent, verifiable data to present 

to the public to demonstrate appropriate 

environmental stewardship, and a better 

understanding of their emission levels 

and sources to identify opportunities to 

reduce emissions. Such monitoring 

allows for inclusion of standardized 

GHG data into environmental 

management systems, providing the 

necessary information to achieve and 

disseminate their environmental 

achievements. 

Standardization will also be a benefit 

to industry, once facilities invest in the 

institutional knowledge and systems to 

report emissions, the cost of monitoring 

should fall and the accuracy of the 

accounting should improve. A 

standardized reporting program will 

also allow for facilities to benchmark 

themselves against similar facilities to 

understand better their relative standing 

within their industry. 

Section VI of the RIA for the Final 

MRR summarizes the anticipated 

benefits of the finalized rule, which 

include providing the government with 

sound data on which to base future 

policies and providing industry and the 

public independently verified 

information documenting firms’ 

environmental performance. While EPA 

has not quantified the benefits of the 

mandatory reporting rule, EPA believes 

that they are substantial and outweigh 

the estimated costs. 

IV. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

Under Executive Order (EO) 12866 

(58 FR 51735, October 4, 1993), this 

action is a ‘‘significant regulatory action’’ 

because it raises novel legal or policy 

issues arising out of legal mandates, the 

President’s priorities, or the principles 

set forth in the EO. Accordingly, EPA 

submitted this action to the Office of 

Management and Budget (OMB) for 

review under EO 12866. 

B. Paperwork Reduction Act 

The information collection 

requirements in this proposed rule have 

been submitted for approval to the 

Office of Management and Budget 

(OMB) under the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. The 

Information Collection Request (ICR) 

document prepared by EPA has been 

assigned EPA ICR number 2376.01. 

EPA plans to collect complete and 

accurate facility-level GHG emissions 

from the petroleum and natural gas 

industry. Accurate and timely 

information on GHG emissions is 

essential for informing future climate 

change policy decisions. Through data 

collected under this proposed rule, EPA 

will gain a better understanding of the 

relative emissions of different segments 

of the petroleum and natural gas 

industry and the distribution of 

emissions from individual facilities 

within those industries. The facilityspecific data will also improve our 

understanding of the factors that 

influence GHG emission rates and 

actions that facilities are already taking 

to reduce emissions. Additionally, EPA 

will be able to track the trend of 

emissions from facilities within the 

petroleum and natural gas industry over 

time, particularly in response to policies 

and potential regulations. The data 

collected by this proposed rule will 

improve EPA’s ability to formulate 

climate change policy options and to 

assess which segments of the petroleum 

and gas industry would be affected, and 

how these segments would be affected 

by the options. 

This information collection is 

mandatory and will be carried out under 

CAA section 114. Information identified 

and marked as CBI will not be disclosed 

except in accordance with procedures 

set forth in 40 CFR part 2. However, 

emissions data collected under CAA 

section 114 cannot generally be claimed 

as CBI and will be made public.10

The projected cost and hour burden 

for non-federal respondents is $37.8 

million and 478,774 hours per year. The 


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11Burden 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. 

estimated average burden per response 

is 98.2 hours; the frequency of response 

is annual for all respondents that must 

comply with the proposed rule’s 

reporting requirements; and the 

estimated average number of likely 

respondents per year is 3,038. The cost 

burden to respondents resulting from 

the collection of information includes 

the total capital cost annualized over the 

equipment’s expected useful life 

(averaging $5.3 million), a total 

operation and maintenance component 

(averaging $1.6 million per year), and a 

labor cost component (averaging $30.9 

million per year).11 Burden is defined at 

5 CFR 1320.3(b). 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. 

To comment on the Agency’s need for 

this information, the accuracy of the 

provided burden estimates, and any 

suggested methods for minimizing 

respondent burden, EPA has established 

a public docket for this rule, which 

includes this ICR, under Docket ID 

number (EPA–HQ–OAR–2009–0923). 

Submit any comments related to the ICR 

to EPA and OMB. See ADDRESSES

section at the beginning of this notice 

for where to submit comments to EPA. 

Send comments to OMB at the Office of 

Information and Regulatory Affairs, 

Office of Management and Budget, 725 

17th Street, NW., Washington, DC 

20503, Attention: Desk Office for EPA. 

Since OMB is required to make a 

decision concerning the ICR between 30 

and 60 days after April 12, 2010, a 

comment to OMB is best assured of 

having its full effect if OMB receives it 

by May 12, 2010. The final rule will 

respond to any OMB or public 

comments on the information collection 

requirements contained in this proposal. 

C. Regulatory Flexibility Act (RFA) 

The RFA generally requires an agency 

to prepare a regulatory flexibility 

analysis of any rule subject to notice 

and comment rulemaking requirements 

under the Administrative Procedure Act 

or any other statute unless the agency 

certifies that the rule will not have a 

significant economic impact on a 

substantial number of small entities. 

Small entities include small businesses, 

small organizations, and small 

governmental jurisdictions. 

For purposes of assessing the impacts 

of this proposed rule on small entities, 

small entity is defined as: (1) A small 

business as defined by the Small 

Business Administration’s regulations at 

13 CFR 121.201; (2) a small 

governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

population of less than 50,000; and (3) 

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of today’s proposed rule on 

small entities, I certify that this action 

will not have a significant economic 

impact on a substantial number of small 

entities. The small entities directly 

regulated by this proposed rule include 

small businesses in the petroleum and 

natural gas industry, small 

governmental jurisdictions and small 

non-profits. We have determined that 

some small businesses will be affected 

because their production processes emit 

GHGs that must be reported. 

The small entities directly regulated 

by this proposed rule include small 

businesses in the petroleum and gas 

industry, small governmental 

jurisdictions and small non-profits. We 

have determined that some small 

businesses will be affected because their 

production processes emit GHGs that 

must be reported. 

For affected small entities, EPA 

conducted a screening assessment 

comparing compliance costs for affected 

industry segments to petroleum and gasspecific data on revenues for small 

businesses. This ratio constitutes a 

‘‘sales’’ test that computes the 

annualized compliance costs of this 

proposed rule as a percentage of sales 

and determines whether the ratio 

exceeds some level (e.g., 1 percent or 3 

percent). The cost-to-sales ratios were 

constructed at the establishment level 

(average compliance cost for the 

establishment/average establishment 

revenues). 

As shown in Table W–10, the average 

ratio of annualized reporting program 

costs to receipts of establishments 

owned by model small enterprises was 

less than 1 percent for industries 

presumed likely to have small 

businesses covered by the reporting 

program. Although the costs to receipts 

for entities with 1–20 employees is over 

1 percent, these facilities would likely 

not exceed the proposed 25,000 mtCO2e 

threshold, a threshold supported by 

many stakeholders as one that 

sufficiently captures the majority of 

GHG emissions while excluding small 

facilities. Further, these sales tests 

examine the average establishment’s 

total annualized mandatory reporting 

costs to the average establishment 

receipts for enterprises within several 

employment categories. The average 

entity costs used to compute the sales 

test are the same across all of these 

enterprise size categories. As a result, 

the sales-test will overstate the cost-toreceipt ratio for establishments owned 

by small businesses, because the 

reporting costs are likely lower than 

average entity estimates provided by the 

engineering cost analysis. 

The screening analysis thus indicates 

that the proposed rule will not have a 

significant economic impact on a 

substantial number of small entities. 

The screening assessment for small 

governments for the Final MRR 

compared the sum of average costs of 

compliance for combustion, local 

distribution companies, and landfills to 

average revenues for small governments. 

Even for a small government owning all 

three source types, the costs constitute 

less than 1 percent of average revenues 

for the smallest category of governments 

(those with fewer than 10,000 people). 

Although this proposed rule will not 

have a significant economic impact on 

a substantial number of small entities, 

EPA nonetheless took several steps to 

reduce the impact of this proposed rule 

on small entities. For example, EPA 

determined appropriate thresholds that 

reduce the number of small businesses 

reporting. In addition, EPA is proposing 

different monitoring methods for 

different emissions sources, requiring 

direct measurement only for selected 

sources. Also, EPA is proposing annual 

instead of more frequent reporting. 

Through comprehensive outreach 

activities prior to proposal of the initial 

rule, EPA held approximately 100 

meetings and/or conference calls with 

representatives of the primary audience 

groups, including numerous trade 

associations and industries in the 

petroleum and gas industry that include 

small business members. EPA’s 

outreach activities prior to proposal of 

the initial rule are documented in the 

memorandum, ‘‘Summary of EPA 

Outreach Activities for Developing the 

Greenhouse Gas Reporting Rule,’’ 

located in Docket No. EPA–HQ–OAR– 

2008–0508–053. After the initial 

proposal, EPA posted a guide for small 

businesses on the EPA GHG reporting 

rule Web site, along with a general fact 

sheet for the rule, information sheets for 

every source category, and an FAQ 

document. EPA also operated a hotline 


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to answer questions about the proposed 

rule. We continued to meet with 

stakeholders and entered 

documentation of all meetings into the 

docket. 

During rule implementation, EPA 

would maintain an ‘‘open door’’ policy 

for stakeholders to ask questions about 

the proposed rule or provide 

suggestions to EPA about the types of 

compliance assistance that would be 

useful to small businesses. EPA intends 

to develop a range of compliance 

assistance tools and materials and 

conduct extensive outreach for the 

proposed rule. 

We have therefore concluded that 

today’s proposed rule will not have a 

significant economic impact on a 

substantial number of small entities. We 

continue to be interested in the 

potential impacts of the proposed rule 

on small entities and welcome 

comments on issues related to such 

impacts. 

D. Unfunded Mandates Reform Act 

(UMRA) 

The UMRA seeks to protect State, 

local, and Tribal governments from the 

imposition of unfunded Federal 

mandates. In addition, the Act seeks to 

strengthen the partnership between the 

Federal government and State, local, 

and Tribal governments and ensure that 

the Federal government covers the costs 

incurred during compliance with 

Federal mandates. 

Title II of the UMRA of 1995, Public 

Law 104–4, establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on State, local, 

and tribal governments and the private 

segment. Under section 202 of UMRA, 

EPA generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with Federal mandates that may result 

in expenditures to State, local, and 

Tribal governments, in the aggregate, or 

to the private segment, of $100 million 

or more in any one year. 

Before promulgating an EPA rule for 

which a written statement is needed, 

section 205 of UMRA generally requires 

EPA to identify and consider a 

reasonable number of regulatory 

alternatives and adopt the least costly, 

most cost-effective or least burdensome 

alternative that achieves the objectives 

of the rule. The provisions of section 

205 do not apply when they are 

inconsistent with applicable law. 

Moreover, section 205 allows EPA to 

adopt an alternative other than the least 

costly, most cost-effective or least 

burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. 

Before EPA establishes any regulatory 

requirements that may significantly or 

uniquely affect small governments, 

including Tribal governments, it must 

have developed under section 203 of 

UMRA a small government agency plan. 

The plan must provide for notifying 

potentially affected small governments, 

enabling officials of affected small 

governments to have meaningful and 

timely input in the development of EPA 

regulatory proposals with significant 

Federal intergovernmental mandates, 

and informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

EPA has determined that the Subpart 

W rule does not contain a Federal 

mandate that may result in expenditures 

of $100 million or more for State, local, 

and Tribal governments, in the 

aggregate, or the private segment in any 

one year. Expenditures associated with 

compliance, defined as the incremental 

costs beyond the existing regulations 

will not surpass $100 million in the 

aggregate in any year. Thus, today’s rule 

is not subject to the requirements of 

sections 202 and 205 of UMRA. 

This rule is also not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. This 

regulation applies to facilities that 

directly emit greenhouse gases. It does 

not apply to governmental entities 

unless the government entity owns a 

facility in the petroleum and gas 

industry that directly emits greenhouse 

gases above threshold levels. In 

addition, this proposed rule does not 

impose any implementation 

responsibilities on State, local, or Tribal 

governments and it is not expected to 

increase the cost of existing regulatory 

programs managed by those 

governments. Thus, the impact on 

governments affected by the proposed 

rule is expected to be minimal. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the States, on the 

relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. This regulation 

applies directly to petroleum and 

natural gas facilities that emit 

greenhouse gases. Few, if any, state or 

local government facilities would be 

affected. This regulation also does not 

limit the power of States or localities to 

collect GHG data and/or regulate GHG 

emissions. Thus, Executive Order 13132 

does not apply to this action. 

In the spirit of Executive Order 13132, 

and consistent with EPA policy to 

promote communications between EPA 

and State and local governments, EPA 

specifically solicits comment on this 

proposed action from State and local 

officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

EPA has concluded that this action 

may have tribal implications. However, 

it will neither impose substantial direct 

compliance costs on tribal governments, 

nor preempt Tribal law. This regulation 

would apply directly to petroleum and 

natural gas facilities that emit 

greenhouses gases. Although few 

facilities that would be subject to the 

rule are likely to be owned by tribal 

governments, EPA has sought 

opportunities to provide information to 

tribal governments and representatives 

during rule development. EPA 

consulted with tribal officials early in 

the process of developing this regulation 

to permit them to have meaningful and 

timely input into its development. EPA 

sought opportunities to provide 

information to Tribal governments and 

representatives during development of 

the mandatory GHG reporting rule that 

was proposed in April 2009 and 

finalized in September 2009. Today’s 

action is a supplemental proposal to 

that rule. In consultation with EPA’s 

American Indian Environment Office, 

EPA’s outreach plan included tribes. 

EPA conducted several conference calls 

with Tribal organizations during the 

proposal phase. For example, EPA staff 

provided information to tribes through 

conference calls with multiple Indian 

working groups and organizations at 

EPA that interact with tribes and 

through individual calls with two Tribal 

board members of TCR. In addition, 

EPA prepared a short article on the GHG 

reporting rule that appeared on the front 

page of a Tribal newsletter—Tribal Air 

News—that was distributed to EPA/ 

OAQPS’s network of Tribal 

organizations. EPA gave a presentation 

on various climate efforts, including the 

mandatory reporting rule, at the 

National Tribal Conference on 

Environmental Management on June 

24–26, 2008. In addition, EPA had 

copies of a short information sheet 

distributed at a meeting of the National 

Tribal Caucus. See the ‘‘Summary of 

EPA Outreach Activities for Developing 

the GHG reporting rule,’’ in Docket No. 

EPA–HQ–OAR–2008–0508–055 for a 

complete list of Tribal contacts. EPA 


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participated in a conference call with 

Tribal air coordinators in April 2009 

and prepared a guidance sheet for Tribal 

governments on the proposed rule. It 

was posted on the MRR Web site and 

published in the Tribal Air Newsletter. 

EPA specifically solicits additional 

comment on this proposed rule from 

Tribal officials. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

EPA interprets EO 13045 (62 FR 

19885, April 23, 1997) as applying only 

to those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the EO has the potential to influence the 

regulation. This action is not subject to 

EO 13045 because it does not establish 

an environmental standard intended to 

mitigate health or safety risks. 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This proposed rule is not a 

‘‘significant energy action’’ as defined in 

EO 13211 (66 FR 28355, May 22, 2001) 

because it is not likely to have a 

significant adverse effect on the supply, 

distribution, or use of energy. Further, 

we have concluded that this proposed 

rule is not likely to have any adverse 

energy effects. This proposed rule 

relates to monitoring, reporting and 

recordkeeping at petroleum and gas 

facilities that emit over 25,000 mtCO2e 

and does not impact energy supply, 

distribution or use. Therefore, we 

conclude that this proposed rule is not 

likely to have any adverse effects on 

energy supply, distribution, or use. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law 104– 

113 (15 U.S.C. 272 note) directs EPA to 

use voluntary consensus standards in its 

regulatory activities unless to do so 

would be inconsistent with applicable 

law or otherwise impractical. Voluntary 

consensus standards are technical 

standards (e.g., materials specifications, 

test methods, sampling procedures, and 

business practices) that are developed or 

adopted by voluntary consensus 

standards bodies. NTTAA directs EPA 

to provide Congress, through OMB, 

explanations when the Agency decides 

not to use available and applicable 

voluntary consensus standards. 

This rulemaking involves technical 

standards. EPA provides the flexibility 

to use any one of the voluntary 

consensus standards from at least seven 

different voluntary consensus standards 

bodies, including the following: ASTM, 

ASME, ISO, Gas Processors Association, 

and American Gas Association. These 

voluntary consensus standards will help 

facilities monitor, report, and keep 

records of greenhouse gas emissions. No 

new test methods were developed for 

this proposed rule. Instead, from 

existing rules for source categories and 

voluntary greenhouse gas programs, 

EPA identified existing means of 

monitoring, reporting, and keeping 

records of greenhouse gas emissions. 

The existing methods (voluntary 

consensus standards) include a broad 

range of measurement techniques, 

including many for combustion sources 

such as methods to analyze fuel and 

measure its heating value; methods to 

measure gas or liquid flow; and methods 

to gauge and measure petroleum and 

petroleum products. 

By incorporating voluntary consensus 

standards into this proposed rule, EPA 

is both meeting the requirements of the 

NTTAA and presenting multiple 

options and flexibility for measuring 

greenhouse gas emissions. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order (EO) 12898 (59 FR 

7629 (Feb. 16, 1994)) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

Federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

EPA has determined that this 

proposed rule will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations 

because it does not affect the level of 

protection provided to human health or 

the environment because it is a rule 

addressing information collection and 

reporting procedures. 

List of Subjects in 40 CFR Part 98 

Environmental protection, 

Administrative practice and procedure, 

Greenhouse gases, Incorporation by 

reference, Suppliers, Reporting and 

recordkeeping requirements. 

Dated: March 22, 2010. 

Lisa P. Jackson, 

Administrator. 

For the reasons stated in the 

preamble, the Environmental Protection 

Agency proposes to amend 40 CFR part 

98 as follows: 

PART 98—MANDATORY 

GREENHOUSE GAS REPORTING 

1. The authority citation for part 98 

continues to read as follows: 

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

Subpart A—[Amended] 

2. Section 98.2 is amended by revising 

paragraph (a) introductory text to read 

as follows: 

§ 98.2 Who must report? 

(a) The GHG reporting requirements 

and related monitoring, recordkeeping, 

and reporting requirements of this part 

apply to the owners and operators of 

any facility that is located in the United 

States or under or attached to the Outer 

Continental Shelf (as defined in 43 

U.S.C. 1331) and that meets the 

requirements of either paragraph (a)(1), 

(a)(2), or (a)(3) of this section; and any 

supplier that meets the requirements of 

paragraph (a)(4) of this section: 

* * * * * 

3. Section 98.6 is amended by adding 

the following definitions in alphabetical 

order and revising the definition of 

‘‘United States’’ to read as follows: 

§ 98.6 Definitions. 

Absorbent circulation pump means a 

pump commonly powered by natural 

gas pressure that circulates the 

absorbent liquid between the absorbent 

regenerator and natural gas contactor. 

* * * * * 

Acid Gas means hydrogen sulfide 

(H2S) and carbon dioxide (CO2) 

contaminants that are separated from 

sour natural gas by an acid gas removal. 

Acid Gas Removal unit (AGR) means 

a process unit that separates hydrogen 

sulfide and/or carbon dioxide from sour 

natural gas using liquid or solid 

absorbents or membrane separators. 

Acid gas removal vent stack emissions 

mean the acid gas separated from the 

acid gas absorbing medium (e.g., an 

amine solution) and released with 

methane and other light hydrocarbons 

to the atmosphere or a flare. 

* * * * * 

Air injected flare means a flare in 

which air is blown into the base of a 

flare stack to induce complete 

combustion of low Btu natural gas (i.e., 


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high non-combustible component 

content). 

* * * * * 

Blowdown vent stack emissions mean 

natural gas released due to maintenance 

and/or blowdown operations including 

but not limited to compressor 

blowdown and emergency shut-down 

(ESD) system testing. 

* * * * * 

Calibrated bag means a flexible, nonelastic, anti-static bag of a calibrated 

volume that can be affixed to a emitting 

source such that the emissions inflate 

the bag to its calibrated volume. 

* * * * * 

Centrifugal compressor means any 

equipment that increases the pressure of 

a process natural gas by centrifugal 

action, employing rotating movement of 

the driven shaft. 

Centrifugal compressor dry seals 

mean a series of rings around the 

compressor shaft where it exits the 

compressor case that operates 

mechanically under the opposing forces 

to prevent natural gas from escaping to 

the atmosphere. 

Centrifugal compressor dry seals 

emissions mean natural gas released 

from a dry seal vent pipe and/or the seal 

face around the rotating shaft where it 

exits one or both ends of the compressor 

case. 

Centrifugal compressor wet seal 

degassing venting emissions means 

emissions that occur when the highpressure oil barriers for centrifugal 

compressors are depressurized to 

release absorbed natural gas. Highpressure oil is used as a barrier against 

escaping gas in centrifugal compressor 

shafts. Very little gas escapes through 

the oil barrier, but under high pressure, 

considerably more gas is absorbed by 

the oil. The seal oil is purged of the 

absorbed gas (using heaters, flash tanks, 

and degassing techniques) and 

recirculated. The separated gas is 

commonly vented to the atmosphere. 

* * * * * 

Coal Bed Methane (CBM) means 

natural gas which is extracted from 

underground coal deposits or ‘‘beds.’’ 

* * * * * 

Component, for the purposes of 

subpart W only, means but is not 

limited to each metal to metal joint or 

seal of non-welded connection 

separated by a compression gasket, 

screwed thread (with or without thread 

sealing compound), metal to metal 

compression, or fluid barrier through 

which natural gas or liquid can escape 

to the atmosphere. 

Compressor means any machine for 

raising the pressure of a natural gas by 

drawing in low pressure natural gas and 

discharging significantly higher 

pressure natural gas. 

* * * * * 

Condensate means hydrocarbon and 

other liquid separated from natural gas 

that condenses due to changes in the 

temperature, pressure, or both, and 

remains liquid at storage conditions, 

includes both water and hydrocarbon 

liquids. 

* * * * * 

Conventional wells mean gas wells in 

producing fields that do not employ 

hydraulic fracturing to produce 

commercially viable quantities of 

natural gas. 

* * * * * 

Dehydrator means a device in which 

a liquid absorbent (including but not 

limited to desiccant, ethylene glycol, 

diethylene glycol, or triethylene glycol) 

directly contacts a natural gas stream to 

absorb water vapor. 

Dehydrator vent stack emissions 

means natural gas released from a 

natural gas dehydrator system absorbent 

(typically glycol) reboiler or regenerator, 

including stripping natural gas and 

motive natural gas used in absorbent 

circulation pumps. 

* * * * * 

De-methanizer means the natural gas 

processing unit that separates methane 

rich residue gas from the heavier 

hydrocarbons (e.g., ethane, propane, 

butane, pentane-plus) in feed natural 

gas stream). 

* * * * * 

Desiccant means a material used in 

solid-bed dehydrators to remove water 

from raw natural gas by adsorption. 

Desiccants include activated alumina, 

palletized calcium chloride, lithium 

chloride and granular silica gel material. 

Wet natural gas is passed through a bed 

of the granular or pelletized solid 

adsorbent in these dehydrators. As the 

wet gas contacts the surface of the 

particles of desiccant material, water is 

adsorbed on the surface of these 

desiccant particles. Passing through the 

entire desiccant bed, almost all of the 

water is adsorbed onto the desiccant 

material, leaving the dry gas to exit the 

contactor. 

* * * * * 

E&P Tank means the most current 

version of an exploration and 

production field tank emissions 

equilibrium program that estimates 

flashing, working and standing losses of 

hydrocarbons, including methane, from 

produced crude oil and gas condensate. 

Equal or successors to E&P Tank 

Version 2.0 for Windows Software. 

Copyright (C) 1996–1999 by The 

American Petroleum Institute and The 

Gas Research Institute. 

* * * * * 

Engineering estimation, for purposes 

of subpart W, means an estimate of 

emissions based on engineering 

principles applied to measured and/or 

approximated physical parameters such 

as dimensions of containment, actual 

pressures, actual temperatures, and 

compositions. 

Enhanced Oil Recovery (EOR) means 

the use of certain methods such as water 

flooding or gas injection into existing 

wells to increase the recovery of crude 

oil from a reservoir. In the context of 

this rule, EOR applies to injection of 

critical phase carbon dioxide into a 

crude oil reservoir to enhance the 

recovery of oil. 

* * * * * 

Field means standardized field names 

and codes of all oil and gas fields 

identified in the United States as 

defined by the Energy Information 

Administration Oil and Gas Field Code 

Master List. 

* * * * * 

Flare combustion means unburned 

hydrocarbons including CH4, CO2, N2O 

emissions resulting from the incomplete 

combustion of gas in flares. 

Flare combustion efficiency means the 

fraction of natural gas, on a volume or 

mole basis, that is combusted at the flare 

burner tip. 

* * * * * 

Fugitive emissions means those 

emissions which are unintentional and 

could not reasonably pass through a 

stack, chimney, vent, or other 

functionally-equivalent opening. 

Fugitive emissions detection means 

the process of identifying emissions 

from equipment, components, and other 

point sources. 

Gas conditions mean the actual 

temperature, volume, and pressure of a 

gas sample. 

* * * * * 

Gas gathering/booster stations mean 

centralized stations where produced 

natural gas from individual wells is comingled, compressed for transport to 

processing plants, transmission and 

distribution systems, and other 

gathering/booster stations which comingle gas from multiple production 

gathering/booster stations. Such stations 

may include gas dehydration, gravity 

separation of liquids (both hydrocarbon 

and water), pipeline pig launchers and 

receivers, and gas powered pneumatic 

devices. 

* * * * * 

Gas to oil ratio (GOR) means the ratio 

of the volume of gas at standard 


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temperature and pressure that is 

produced from a volume of oil when 

depressurized to standard temperature 

and pressure. 

* * * * * 

High-Bleed Pneumatic Devices are 

automated flow control devices 

powered by pressurized natural gas and 

used for maintaining a process 

condition such as liquid level, pressure, 

delta-pressure and temperature. Part of 

the gas power stream which is regulated 

by the process condition flows to a 

valve actuator controller where it vents 

(bleeds) to the atmosphere at a rate in 

excess of six standard cubic feet per 

hour. 

* * * * * 

Liquefied natural gas (LNG) means 

natural gas (primarily methane) that has 

been liquefied by reducing its 

temperature to ¥260 degrees Fahrenheit 

at atmospheric pressure. 

LNG boiloff gas means natural gas in 

the gaseous phase that vents from LNG 

storage tanks due to ambient heat 

leakage through the tank insulation and 

heat energy dissipated in the LNG by 

internal pumps. 

Low-Bleed Pneumatic Devices mean 

automated flow control devices 

powered by pressurized natural gas and 

used for maintaining a process 

condition such as liquid level, pressure, 

delta-pressure and temperature. Part of 

the gas power stream which is regulated 

by the process condition flows to a 

valve actuator controller where it vents 

(bleeds) to the atmosphere at a rate 

equal to or less than six standard cubic 

feet per hour. 

* * * * * 

Natural gas driven pneumatic pump 

means a pump that uses pressurized 

natural gas to move a piston or 

diaphragm, which pumps liquids on the 

opposite side of the piston or 

diaphragm. 

* * * * * 

Offshore means seaward of the 

terrestrial borders of the United States, 

including waters subject to the ebb and 

flow of the tide, as well as adjacent 

bays, lakes or other normally standing 

waters, and extending to the outer 

boundaries of the jurisdiction and 

control of the United States under the 

Outer Continental Shelf Lands Act. 

* * * * * 

Onshore petroleum and natural gas 

production owner or operator means the 

entity who is the permitee to operate 

petroleum and natural gas wells on the 

state drilling permit or a state operating 

permit where no drilling permit is 

issued by the state, which operates an 

onshore petroleum and/or natural gas 

production facility (as described in 

§ 98.230(b)(2). Where more than one 

entity are permitees on the state drilling 

permit, or operating permit where no 

drilling permit is issued by the state, the 

permitted entities for the joint facility 

must designate one entity to report all 

emissions from the joint facility. 

* * * * * 

Operating pressure means the 

containment pressure that characterizes 

the normal state of gas or liquid inside 

a particular process, pipeline, vessel or 

tank. 

* * * * * 

Outer Continental Shelf means all 

submerged lands lying seaward and 

outside of the area of lands beneath 

navigable waters as defined in 43 U.S.C. 

§ 1301, and of which the subsoil and 

seabed appertain to the United States 

and are subject to its jurisdiction and 

control. 

* * * * * 

Pump means a device used to raise 

pressure, drive, or increase flow of 

liquid streams in closed or open 

conduits. 

Pump seals means any seal on a pump 

drive shaft used to keep methane and/ 

or carbon dioxide containing light 

liquids from escaping the inside of a 

pump case to the atmosphere. 

Pump seal emissions means 

hydrocarbon gas released from the seal 

face between the pump internal 

chamber and the atmosphere. 

* * * * * 

Reciprocating compressor means a 

piece of equipment that increases the 

pressure of a process natural gas by 

positive displacement, employing linear 

movement of a shaft driving a piston in 

a cylinder. 

Reciprocating compressor rod packing 

means a series of flexible rings in 

machined metal cups that fit around the 

reciprocating compressor piston rod to 

create a seal limiting the amount of 

compressed natural gas that escapes to 

the atmosphere. 

Re-condenser means heat exchangers 

that cool compressed boil-off gas to a 

temperature that will condense natural 

gas to a liquid. 

* * * * * 

Reservoir means a porous and 

permeable underground natural 

formation containing significant 

quantities of hydrocarbon liquids and/or 

gases. A reservoir is characterized by a 

single natural pressure system. 

* * * * * 

Sales oil means produced crude oil or 

condensate measured at the production 

lease automatic custody transfer (LACT) 

meter or custody transfer meter tank 

gauge. 

* * * * * 

Sour natural gas means natural gas 

that contains significant concentrations 

of hydrogen sulfide and/or carbon 

dioxide that exceed the concentrations 

specified for commercially saleable 

natural gas delivered from transmission 

and distribution pipelines. 

* * * * * 

Sweet Gas is natural gas with low 

concentrations of hydrogen sulfide 

(H2S) and/or carbon dioxide (CO2) that 

does not require (or has already had) 

acid gas treatment to meet pipeline 

corrosion-prevention specifications for 

transmission and distribution. 

* * * * * 

Transmission pipeline means high 

pressure cross country pipeline 

transporting sellable quality natural gas 

from production or natural gas 

processing to natural gas distribution 

pressure let-down, metering, regulating 

stations where the natural gas is 

typically odorized before delivery to 

customers. 

* * * * * 

Turbine meter means a flow meter in 

which a gas or liquid flow rate through 

the calibrated tube spins a turbine from 

which the spin rate is detected and 

calibrated to measure the fluid flow rate. 

* * * * * 

Unconventional wells means gas well 

in producing fields that employ 

hydraulic fracturing to enhance gas 

production volumes. 

* * * * * 

United States means the 50 States, the 

District of Columbia, the 

Commonwealth of Puerto Rico, 

American Samoa, the Virgin Islands, 

Guam, and any other Commonwealth, 

territory or possession of the United 

States, as well as the territorial sea as 

defined by Presidential Proclamation 

No. 5928. 

* * * * * 

Vapor recovery system means any 

equipment located at the source of 

potential gas emissions to the 

atmosphere or to a flare, that is 

composed of piping, connections, and, 

if necessary, flow-inducing devices, and 

that is used for routing the gas back into 

the process as a product and/or fuel. 

Vaporization unit means a process 

unit that performs controlled heat input 

to vaporize LNG to supply transmission 

and distribution pipelines or consumers 

with natural gas. 

* * * * * 

Vented emissions means intentional 

or designed releases of CH4 or CO2

containing natural gas or hydrocarbon 

gas (not including stationary 

combustion flue gas), including but not 

limited to process designed flow to the 


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atmosphere through seals or vent pipes, 

equipment blowdown for maintenance, 

and direct venting of gas used to power 

equipment (such as pneumatic devices). 

* * * * * 

Well completions means a process 

that allows for the flow of petroleum or 

natural gas from newly drilled wells to 

expel drilling and reservoir fluids and 

test the reservoir flow characteristics. 

This process includes high-rate backflow of injected water and sand used to 

fracture and prop-open fractures in low 

permeability gas reservoirs. 

Well workover means the performance 

of one or more of a variety of remedial 

operations on producing oil and gas 

wells to try to increase production. This 

process also includes high-rate backflow of injected water and sand used to 

re-fracture and prop-open new fractures 

in existing low permeability gas 

reservoirs. 

Wellhead means the piping, casing, 

tubing and connected valves protruding 

above the Earth’s surface for an oil and/ 

or natural gas well. The wellhead ends 

where the flow line connects to a 

wellhead valve. 

Wet natural gas means natural gas in 

which water vapor exceeds the 

concentration specified for 

commercially saleable natural gas 

delivered from transmission and 

distribution pipelines. This input 

stream to a natural gas dehydrator is 

referred to as ‘‘wet gas’’. 

4. Section 98.7 is amended by adding 

paragraphs (k), (l), and (m) to read as 

follows: 

§ 98.7 What standardized methods are 

incorporated by reference into this part? 

* * * * * 

(k) The following material is available 

for purchase from the Gas Technology 

Institute, 1700 South Mount Prospect 

Road, Des Plaines, Illinois 60018, 

http://www.gastechnology.org. 

(1) GRI–GLYCalc Version 4.0, IBR 

approved for § 98.233(e). 

(2) [Reserved] 

(l) The following material is available 

for purchase from IHS Standards Store, 

Jane’s Information Group, Inc., 110 

North Royal Street, Suite 200, 

Alexandria, Virginia 22314, http:// 

www.ihs.com. 

(1) E&P Tank Version 2.0, IBR 

approved for § 98.233(j) and § 98.236(c). 

(2) [Reserved] 

(m) The following material is 

available for purchase from the 

American Association of Petroleum 

Geologists, 1444 South Boulder Avenue, 

Tulsa, Oklahoma 74119, www.aapg.org. 

(1) AAPG–CSD Geologic Provinces 

Code Map: AAPG Bulletin, Volume 75, 

Number 10 (October 1991), pages 1644– 

1651, IBR approved for § 98.230(b). 

(2) [Reserved] 

5. Add subpart W to read as follows: 

Subpart W—Petroleum and Natural Gas 

Systems 

Sec. 

98.230 Definition of the source category. 

98.231 Reporting threshold. 

98.232 GHGs to report. 

98.233 Calculating GHG emissions. 

98.234 Monitoring and QA/QC 

requirements. 

98.235 Procedures for estimating missing 

data. 

98.236 Data reporting requirements. 

98.237 Records that must be retained. 

98.238 Definitions. 

Subpart W—Petroleum and Natural 

Gas Systems 

§ 98.230 Definition of the source category. 

(a) This source category consists of 

the following: 

(1) Offshore petroleum and natural 

gas production. Offshore petroleum and 

natural gas production is any platform 

structure, affixed temporarily or 

permanently to offshore submerged 

lands, that houses equipment to extract 

hydrocarbons from the ocean or lake 

floor and that transfers such 

hydrocarbons to storage, transport 

vessels, or onshore. In addition, offshore 

production includes secondary platform 

structures and storage tanks associated 

with the platform structure. 

(2) Onshore petroleum and natural 

gas production. Onshore petroleum and 

natural gas production equipment 

means all structures associated with 

wells (including but not limited to 

compressors, generators, or storage 

facilities), piping (including but not 

limited to flowlines or intra-facility 

gathering lines), and portable non-selfpropelled equipment (including but not 

limited to well drilling and completion 

equipment, workover equipment, 

gravity separation equipment, auxiliary 

non-transportation-related equipment, 

and leased, rented or contracted 

equipment) used in the production, 

extraction, recovery, lifting, 

stabilization, separation or treating of 

petroleum and/or natural gas (including 

condensate). This also includes 

associated storage or measurement and 

all systems engaged in gathering 

produced gas from multiple wells, all 

EOR operations using CO2, and all 

petroleum and natural gas production 

located on islands, artificial islands or 

structures connected by a causeway to 

land, an island, or artificial island. 

(3) Onshore natural gas processing 

plants. Natural gas processing plants are 

designed to separate and recover natural 

gas liquids (NGLs) or other non-methane 

gases and liquids from a stream of 

produced natural gas to meet onshore 

natural gas transmission pipeline 

quality specifications through 

equipment performing one or more of 

the following processes: oil and 

condensate removal, water removal, 

separation of natural gas liquids, sulfur 

and carbon dioxide removal, 

fractionation of NGLs, or other 

processes, and also the capture of CO2

separated from natural gas streams for 

delivery outside the facility. In addition, 

field gathering and/or boosting stations 

that gather and process natural gas from 

multiple wellheads, and compress and 

transport natural gas (including but not 

limited to flowlines or intra-facility 

gathering lines or compressors) as feed 

to the natural gas processing plants are 

considered a part of the processing 

plant. Gathering and boosting stations 

that send the natural gas to an onshore 

natural gas transmission compression 

facility, or natural gas distribution 

facility, or to an end user are considered 

stand alone natural gas processing 

facilities. All residue gas compression 

equipment operated by a processing 

plant, whether inside or outside the 

processing plant fence, are considered 

part of natural gas processing plant. 

(4) Onshore natural gas transmission 

compression. Onshore natural gas 

transmission compression means any 

fixed combination of compressors that 

move natural gas at elevated pressure 

from production fields or natural gas 

processing facilities, in transmission 

pipelines, to natural gas distribution 

pipelines, or into storage. In addition, 

transmission compressor station 

includes equipment for liquids 

separation, natural gas dehydration, and 

tanks for the storage of water and 

hydrocarbon liquids. 

(5) Underground natural gas storage. 

Underground natural gas storage means 

subsurface storage, including but not 

limited to, depleted gas or oil reservoirs 

and salt dome caverns utilized for 

storing natural gas that has been 

transferred from its original location for 

the primary purpose of load balancing 

(the process of equalizing the receipt 

and delivery of natural gas); natural gas 

underground storage processes and 

operations (including, but not limited 

to, compression, dehydration and flow 

measurement); and all the wellheads 

connected to the compression units 

located at the facility. 

(6) Liquefied natural gas (LNG) 

storage. LNG storage means onshore 

LNG storage vessels located above 

ground, equipment for liquefying 

natural gas, compressors to capture and 

re-liquefy boil-off-gas, re-condensers, 


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Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 18637 

and vaporization units for regasification of the liquefied natural gas. 

(7) LNG import and export equipment. 

LNG import equipment means all 

onshore or offshore equipment that 

receives imported LNG via ocean 

transport, stores LNG, re-gasifies LNG, 

and delivers re-gasified natural gas to a 

natural gas transmission or distribution 

system. LNG export equipment means 

all onshore or offshore equipment that 

receives natural gas, liquefies natural 

gas, stores LNG, and transfers the LNG 

via ocean transportation to any location, 

including locations in the United States. 

(8) Natural Gas Distribution. Natural 

gas distribution means distribution 

pipelines (not interstate pipelines or 

intrastate pipelines) and metering and 

regulating stations, that physically 

deliver natural gas to end users. 

(b) [Reserved] 

§ 98.231 Reporting threshold. 

(a) You must report GHG emissions 

from petroleum and natural gas systems 

if your facility as defined in § 98.230 

meets the requirements of § 98.2(a)(2). 

(b) For applying the threshold defined 

in § 98.2(a)(2), you must include 

combustion emissions from portable 

equipment that cannot move on 

roadways under its own power and 

drive train and that is stationed at a 

wellhead for more than 30 days in a 

reporting year, including drilling rigs, 

dehydrators, compressors, electrical 

generators, steam boilers, and heaters. 

§ 98.232 GHGs to report. 

(a) You must report CO2 and CH4

emissions from each industry segment 

specified in paragraph (b) through (i) of 

this section. 

(b) For offshore petroleum and natural 

gas production, report emissions from 

all ‘‘stationary fugitive’’ and ‘‘stationary 

vented’’ sources as identified in the 

Minerals Management Service (MMS) 

Gulfwide Offshore Activity Data System 

(GOADS) study (2005 Gulfwide 

Emission Inventory Study MMS 2007– 

067). 

(c) For onshore petroleum and natural 

gas production, report emissions from 

the following source types: 

(1) Natural gas pneumatic high bleed 

device venting. 

(2) Natural gas pneumatic low bleed 

device venting. 

(3) Natural gas driven pneumatic 

pump venting. 

(4) Well venting for liquids unloading. 

(5) Gas well venting during 

conventional well completions. 

(6) Gas well venting during 

unconventional well completions. 

(7) Gas well venting during 

conventional well workovers. 

(8) Gas well venting during 

unconventional well workovers. 

(9) Gathering pipeline fugitives. 

(10) Storage tanks. 

(11) Reciprocating compressor rod 

packing venting. 

(12) Well testing venting and flaring. 

(13) Associated gas venting and 

flaring. 

(14) Dehydrator vent stacks. 

(15) Coal bed methane produced 

water emissions. 

(16) EOR injection pump blowdown. 

(17) Acid gas removal vent stack. 

(18) Hydrocarbon liquids dissolved 

CO2. 

(19) Centrifugal compressor wet seal 

degassing venting. 

(20) Produced water dissolved CO2. 

(21) Fugitive emissions from valves, 

connectors, open ended lines, pressure 

relief valves, compressor starter gas 

vents, pumps, flanges, and other fugitive 

sources (such as instruments, loading 

arms, pressure relief valves, stuffing 

boxes, compressor seals, dump lever 

arms, and breather caps for crude 

services). 

(d) For onshore natural gas 

processing, report emissions from the 

following sources: 

(1) Reciprocating compressor rod 

packing venting. 

(2) Centrifugal compressor wet seal 

degassing venting. 

(3) Storage tanks. 

(4) Blowdown vent stacks. 

(5) Dehydrator vent stacks. 

(6) Acid gas removal vent stack. 

(7) Flare stacks. 

(8) Gathering pipeline fugitives. 

(9) Fugitive emissions from: valves, 

connectors, open ended lines, pressure 

relief valves, meters, and centrifugal 

compressor dry seals. 

(e) For onshore natural gas 

transmission compression, report 

emissions from the following sources: 

(1) Reciprocating compressor rod 

packing venting. 

(2) Centrifugal compressor wet seal 

degassing venting. 

(3) Transmission storage tanks. 

(4) Blowdown vent stacks. 

(5) Natural gas pneumatic high bleed 

device venting. 

(6) Natural gas pneumatic low bleed 

device venting. 

(7) Fugitive emissions from 

connectors, block valves, control valves, 

compressor blowdown valves, pressure 

relief valves, orifice meters, other 

meters, regulators, and open ended 

lines. 

(f) For underground natural gas 

storage, report emissions from the 

following sources: 

(1) Reciprocating compressor rod 

packing venting. 

(2) Centrifugal compressor wet seal 

degassing venting. 

(3) Natural gas pneumatic high bleed 

device venting. 

(4) Natural gas pneumatic low bleed 

device venting. 

(5) Fugitive emissions from 

connectors, block valves, control valves, 

compressor blowdown valves, pressure 

relief valves, orifice meters, other 

meters, regulators, and open ended 

lines. 

(g) For LNG storage, report emissions 

from the following sources: 

(1) Reciprocating compressor rod 

packing venting. 

(2) Centrifugal compressor wet seal 

degassing venting. 

(3) Fugitive emissions from valves; 

pump seals; connectors; vapor recovery 

compressors, and other fugitive sources. 

(h) LNG import and export 

equipment, report emissions from the 

following sources: 

(1) Reciprocating compressor rod 

packing venting. 

(2) Centrifugal compressor wet seal 

degassing venting. 

(3) Blowdown vent stacks. 

(4) Fugitive emissions from valves, 

pump seals, connectors, vapor recovery 

compressors, and other fugitive sources. 

(i) For natural gas distribution, report 

emissions from the following sources: 

(1) Above ground meter regulators 

and gate station fugitive emissions from 

connectors, block valves, control valves, 

pressure relief valves, orifice meters, 

other meters, regulators, and open 

ended lines. 

(2) Below ground meter regulators and 

vault fugitives. 

(3) Pipeline main fugitives. 

(4) Service line fugitives. 

(j) You must report the CO2, CH4, and 

N2O emissions from each flare. 

(k) You must report under subpart C 

of this part (General Stationary Fuel 

Combustion Sources) the emissions of 

CO2, CH4, and N2O from each stationary 

fuel combustion unit by following the 

requirements of subpart C. 

(l) You must report under subpart PP 

of this part (Suppliers of Carbon 

Dioxide), CO2 emissions captured and 

transferred off site by following the 

requirements of subpart PP. 

§ 98.233 Calculating GHG emissions. 

(a) Natural gas pneumatic high bleed 

device venting. Calculate emissions 

from a natural gas pneumatic high bleed 

flow control device venting as follows: 

(1) Calculate vented emissions using 

manufacturer data. 

(i) Obtain from the manufacturer 

specific pneumatic device model 

natural gas bleed rate during normal 

operation. 


srobinson on DSKHWCL6B1PROD with PROPOSALS3
18638 Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 

(ii) Calculate the natural gas 

emissions for each continuous bleed 

device using Equation W–1 of this 

section. 

E BT s,n s = ∗ (Eq. W-1)

Where: 

Es,n = Annual natural gas emissions at 

standard conditions, in cubic feet. 

Bs = Natural gas driven pneumatic device 

bleed rate volume at standard conditions 

in cubic feet per minute, as provided by 

the manufacturer. 

T = Amount of time in minutes that the 

pneumatic device has been operational 

through the reporting period. 

(iii) Both CH4 and CO2 volumetric and 

mass emissions shall be calculated from 

volumetric natural gas emissions using 

calculations in paragraphs (u) and (v) of 

this section. 

(2) If manufacturer data for a specific 

device is not available, then use data for 

a similar device model, size and 

operational characteristics to estimate 

emissions. 

(b) Natural gas pneumatic low bleed 

device venting. Calculate emissions 

from natural gas pneumatic low 

continuous bleed device venting using 

Equation W–2 of this section. 

Mass Count EF GHG Conv s,i i i = ∗ ∗ ∗ ∗∗ 24 365 (Eq. W-2)

Where: 

Masss,i = Annual total mass GHG emissions 

in metric tons per year at standard 

conditions from all natural gas 

pneumatic low bleed device venting, for 

GHG i. 

Count = Total number of natural gas 

pneumatic low bleed devices. 

EF = Population emission factors for natural 

gas pneumatic low bleed device venting 

listed in Tables W–1, W–3, and W–4 of 

this subpart for onshore petroleum and 

natural gas production, onshore natural 

gas transmission, and underground 

natural gas storage facilities, 

respectively. 

GHG i = For onshore petroleum and natural 

gas production facilities, concentration 

of GHG i, CH4 or CO2, in produced 

natural gas; for facilities listed in 

§ 98.230(a)(3) through (a)(8), GHGi 

equals 1. 

Convi = Conversion from standard cubic feet 

to metric tons CO2e; 0.000404 for CH4, 

and 0.00005189 for CO2. 

24 * 365 = Conversion to yearly emissions 

estimate. 

(c) Natural gas driven pneumatic 

pump venting. Calculate emissions from 

natural gas driven pneumatic pump 

venting as follows: 

(1) Calculate emissions using 

manufacturer data. 

(i) Obtain from the manufacturer 

specific pump model natural gas 

emission (or manufacturer ‘‘gas 

consumption’’) per unit volume of liquid 

circulation rate at pump speeds and 

operating pressures. 

(ii) Maintain a log of the amount of 

liquid pumped annually from 

individual pumps. 

(iii) Calculate the natural gas 

emissions for each pump using Equation 

W–3 of this section. 

E FV s,n s = ∗ (Eq. W-3)

Where: 

Es,n = Annual natural gas emissions at 

standard conditions in cubic feet per year. 

Fs = Natural gas driven pneumatic pump 

gas emission in ‘‘emission per volume of 

liquid pumped at operating pressure’’ in scf/ 

gallon at standard conditions, as provided by 

the manufacturer. 

V = Volume of liquid pumped annually in 

gallons/year. 

(iv) Both CH4 and CO2 volumetric and 

mass emissions shall be calculated from 

volumetric natural gas emissions using 

calculations in paragraphs (u) and (v) of 

this section. 

(2) If manufacturer data for a specific 

pump in Equation W–3 is not available, 

then use data for a similar pump model, 

size and operational characteristics to 

estimate emissions. 

(d) Acid gas removal (AGR) vent 

stacks. For AGR (including but not 

limited to processes such as amine, 

membrane, molecular sieve or other 

absorbents and adsorbents), calculate 

emissions for CO2 only (not CH4) using 

Equation W–4 of this section. 

E V Vol V Vol a CO , 21 1 2 2 = ∗ ( ) % % − ∗ ( ) (Eq. W-4)

Where: 

Ea,CO2 = Annual volumetric CO2 emissions at 

ambient condition, in cubic feet per year. 

V1 = Metered total annual volume of natural 

gas flow into AGR unit in cubic feet per 

year at ambient condition. 

%Vol1 = Volume weighted CO2 content of 

natural gas into the AGR unit. 

V2 = Metered total annual volume of natural 

gas flow out of the AGR unit in cubic feet 

per year at ambient condition. 

%Vol2 = Volume weighted CO2 content of 

natural gas out of the AGR unit. 

(1) If a continuous gas analyzer is 

installed, then the continuous gas 

analyzer results must be used. If 

continuous gas analyzer is not available, 

quarterly gas samples must be taken to 

determine %Vol1 and %Vol2 according 

to methods set forth in § 98.234(b). 

(2) Calculate CO2 volumetric 

emissions at standard conditions using 

calculations in paragraph (t) of this 

section. 

(3) Mass CO2 emissions shall be 

calculated from volumetric CO2

emissions using calculations in 

paragraphs (u) and (v) of this section. 

(e) Dehydrator vent stacks. For 

dehydrator vent stacks without vapor 

recovery or thermal control devices, 

calculate annual mass CH4 and CO2

emissions at standard temperature and 

pressure (STP) conditions using the 

simulation software package GRI– 

GLYCalc Version 4.0 (incorporated by 

reference, see § 98.7). 

(1) A minimum of the following 

parameters must be used for 

characterizing emissions from 

dehydrators: 

(i) Feed natural gas flow rate. 

(ii) Feed natural gas water content. 

(iii) Outlet natural gas water content. 

(iv) Absorbent circulation pump type 

(natural gas pneumatic/air pneumatic/ 

electric). 

(v) Absorbent circulation rate. 

(vi) Absorbent type: Including, but not 

limited to, triethylene glycol (TEG), 

diethylene glycol (DEG) or ethylene 

glycol (EG). 

(vii) Use of stripping natural gas. 

(viii) Use of flash tank separator (and 

disposition of recovered gas). 

(ix) Hours operated. 

(x) Wet natural gas temperature, 

pressure, and composition. 

(2) Calculate annual emissions from 

dehydrator vent stacks to flares or 

regenerator fire-box/fire tubes as 

follows: 

(i) Use the dehydrator vent stack 

volume and gas composition as 

determined in paragraph (e)(1) of this 

section. 


srobinson on DSKHWCL6B1PROD with PROPOSALS3EP12AP10.082</MATH> EP12AP10.000</MATH> EP12AP10.001</MATH> EP12AP10.002</MATH>
Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 18639 

(ii) Use the calculation methodology 

of flare stacks in paragraph (n) of this 

section to determine dehydrator vent 

stack emissions from the flare or 

regenerator combustion gas vent. 

(3) Dehydrators that use desiccant 

shall calculate emissions from the 

amount of gas vented from the vessel 

every time it is depressurized for the 

desiccant refilling process using 

Equation W–5 of this section. 

E

H D P P G days yr

P T cf Mcf s n,

% /

, / = ( ) ∗ ∗∗ ∗ ∗

( ) ∗ ∗∗

2

2

1

365

4 1 000 (Eq. W-5)

Where: 

Es,n = Annual natural gas emissions at 

standard conditions. 

H = Height of the dehydrator vessel (ft). 

D = Inside diameter of the vessel (ft). 

P1 = Atmospheric pressure (psia). 

P2 = Pressure of the gas (psia). 

P = pi (3.14). 

%G = Percent of packed vessel volume that 

is gas. 

T = Time between refilling (days). 

(i) Both CH4 and CO2 volumetric and 

mass emissions shall be calculated from 

volumetric natural gas emissions using 

calculations in paragraphs (u) and (v) of 

this section. 

(f) Well venting for liquids 

unloadings. 

(1) The emissions for well venting for 

liquids unloading shall be determined 

using either of the calculation 

methodologies described in paragraph 

(f)(1) of this section. The same 

calculation methodology must be used 

for the entire volume for the reporting 

year. 

(i) Calculation Methodology 1. For 

each unique well tubing diameter and 

producing horizon/formation 

combination in each gas producing field 

where gas wells are vented to the 

atmosphere to expel liquids 

accumulated in the tubing, a recording 

flow meter shall be installed on the vent 

line used to vent gas from the well (e.g., 

on the vent line off the wellhead 

separator or atmospheric storage tank) 

according to methods set forth in 

§ 98.234(b). Calculate emissions from 

well venting for liquids unloading using 

Equation W–6 of this section. 

E T FR a n, = ∗ (Eq. W-6)

Where: 

Ea,n = Annual natural gas emissions at 

ambient conditions in cubic feet. 

T = Cumulative amount of time in hours of 

well venting during the year. 

FR = Flow Rate in cubic feet per hour, under 

ambient conditions as required in 

paragraph (f)(1)(i)(A), (f)(1)(i)(B) and 

(f)(1)(i)(C) of this section. 

Calculate natural gas volumetric 

emissions at standard conditions using 

calculations in paragraph (t) of this 

section. Both CH4 and CO2 volumetric 

and mass emissions shall be calculated 

from volumetric natural gas emissions 

using calculations in paragraphs (u) and 

(v) of this section. 

(A) The average flow rate per minute 

of venting is calculated for each unique 

tubing diameter and producing horizon/ 

formation combination in each 

producing field. 

(B) This factor is applied to all wells 

in the field that have the same tubing 

diameter and producing horizon/ 

formation combination, multiplied by 

the number of minutes of venting from 

all wells of the same tubing diameter 

and producing horizon/formation 

combination in that field. 

(C) A new emission factor is 

calculated every other year for each 

reporting field and horizon. 

(ii) Calculation Methodology 2. 

Calculate emissions from each well 

venting for liquids unloading using 

Equation W–7 of this section. 

E CD WD SP V SFR HR s n, = × { } ( ) . {} ∗ ∗ ∗∗ + ∗ − 0 37 10 3 2 (Eq. W-7)

Where: 

Es,n = Annual natural gas emissions at 

standard conditions, in cubic feet/year. 

0.37 × 10¥3 = {pi(3.14)/4}/{(14.7*144) psia 

converted to pounds per square feet} 

CD = Casing diameter (inches). 

WD = Well depth (feet). 

SP = Shut-in pressure (psig). 

V = Number of vents per year. 

SFR = Sales flow rate of gas well in cubic feet 

per hour. 

HR = Hours that the well was left open to the 

atmosphere during unloading. 

(A) Both CH4 and CO2 volumetric and 

mass emissions shall be calculated from 

volumetric natural gas emissions using 

calculations in paragraphs (u) and (v) of 

this section. 

(B) [Reserved] 

(g) Gas well venting during 

unconventional well completions and 

workovers. Calculate emissions from gas 

unconventional well venting during 

well completions and workovers from 

hydraulic fracturing using Equation 

W–8 of this section. Calculate natural 

gas volumetric emissions at standard 

conditions using calculations in 

paragraph (t) of this section. Both CH4

and CO2 volumetric and mass emissions 

shall be calculated from volumetric 

natural gas emissions using calculations 

in paragraphs (u) and (v) of this section. 

E T FR a n, = ∗ (Eq. W-8)

Where: 

Ea,n = Annual natural gas vented emissions at 

ambient conditions in cubic feet. 

T = Cumulative amount of time in hours of 

well venting during the year. 

FR = Flow Rate in cubic feet per hour, under 

ambient conditions, as required in 

paragraph (g)(1) of this section. 

(1) The flow rate for gas well venting 

during well completions and workovers 

from hydraulic fracturing shall be 

determined using either of the 

calculation methodologies described in 

this paragraph (g)(1). The same 

calculation methodology must be used 

for the entire volume for the reporting 

year. 

(i) Calculation methodology 1. For 

one well completion in each gas 

producing field and for one well 

workover in each gas producing field, a 

recording flow meter shall be installed 

on the vent line during each well 

unloading event according to methods 

set forth in § 98.234(b). 

(A) The average flow rate in cubic feet 

per minute of venting is calculated for 

one well completion in each field and 

for one well workover in each field. 

(B) The respective flow rates are 

applied to all well completions in the 

field and to all well workovers in the 

field, multiplied by the number of 

minutes of venting of all well 

completions and workovers, 

respectively, in that field. 


srobinson on DSKHWCL6B1PROD with PROPOSALS3EP12AP10.003</MATH> EP12AP10.004</MATH> EP12AP10.005</MATH> EP12AP10.006</MATH>
18640 Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 

(C) New flow rates for completions 

and workovers are calculated every 

other year for each reporting field and 

horizon. 

(ii) Calculation Methodology 2. For 

one well completion in each gas 

producing field and for one well 

workover in each gas producing field, 

record the pressures measured before 

and after the well choke according to 

methods set forth in § 98.234(b). 

(A) The average flow rate in cubic feet 

per minute of venting across the choke 

is calculated for one well completion in 

each field and for one well workover in 

each field. 

(B) The respective flow rates are 

applied to all well completions in the 

field and to all well workovers in the 

field, multiplied by the number of 

minutes of venting of all well 

completions and workovers in that field. 

(C) New flow rates for completions 

and workovers are calculated every 

other year for each reporting field and 

horizon. 

(iii) Calculate natural gas volumetric 

emissions at standard conditions using 

calculations in paragraph (t) of this 

section. 

(iv) Both CH4 and CO2 volumetric and 

mass emissions shall be calculated from 

volumetric natural gas emissions using 

calculations in paragraphs (u) and (v) of 

this section. 

(2) Calculate annual emissions from 

gas well venting during well 

completions and workovers to flares as 

follows: 

(i) Use the gas well venting volume 

during well completions and workovers 

as determined in paragraph (g)(1) of this 

section. 

(ii) Use the calculation methodology 

of flare stacks in paragraph (n) of this 

section to determine gas well venting 

during well completions and workovers 

emissions from the flare. 

(h) Gas well venting during 

conventional well completions and 

workovers. Calculate emissions from 

each gas well venting during 

conventional well completions and 

workovers using Equation W–9 of this 

section: 

E VT a,n = ∗ (Eq. W-9)

Where: 

Ea,n = Annual emissions in cubic feet at 

ambient conditions from gas well 

venting during conventional well 

completions or workovers. 

V = Daily gas production rate in cubic feet 

per minute. 

T = Cumulative amount of time of well 

venting in minutes during the year. 

(i) Calculate natural gas volumetric 

emissions at standard conditions using 

calculations in paragraph (t) of this 

section. 

(ii) Both CH4 and CO2 volumetric and 

mass emissions shall be calculated from 

volumetric natural gas emissions using 

calculations in paragraphs (u) and (v) of 

this section. 

(iii) Blowdown vent stacks. Calculate 

blowdown vent stack emissions as 

follows: 

(1) Calculate the total volume 

(including, but not limited to, pipelines, 

compressor case or cylinders, 

manifolds, suction and discharge bottles 

and vessels) between isolation valves. 

(2) Retain logs of the number of 

blowdowns for each equipment type. 

(3) Calculate the total annual venting 

emissions using Equation W–10 of this 

section: 

E NV a,n v = ∗ (Eq. W-10)

Where: 

Ea,n = Annual natural gas venting emissions 

at ambient conditions from blowdowns 

in cubic feet. 

N = Number of blowdowns for the equipment 

in reporting year. 

Vv = Total volume of blowdown equipment 

chambers (including, but not limited to, 

pipelines, compressors and vessels) 

between isolation valves in cubic feet. 

(4) Calculate natural gas volumetric 

emissions at standard conditions using 

calculations in paragraph (t) of this 

section. 

(5) Calculate both CH4 and CO2

volumetric and mass emissions from 

volumetric natural gas emissions using 

calculations in paragraphs (u) and (v) of 

this section. 

(j) Onshore production and processing 

storage tanks. For emissions from 

atmospheric pressure storage tanks 

receiving produced liquids from 

onshore petroleum and natural gas 

production facilities (including 

stationary liquid storage not owned or 

operated by the reporter) and onshore 

natural gas processing facilities, 

calculate annual CH4 and CO2 emissions 

using the latest software package for 

E&P Tank (incorporated by reference, 

see § 98.7). 

(1) A minimum of the following 

parameters must be used to characterize 

emissions from liquid transfer to 

atmospheric pressure storage tanks. 

(i) Separator oil composition. 

(ii) Separator temperature. 

(iii) Separator pressure. 

(iv) Sales oil API gravity. 

(v) Sales oil production rate. 

(vi) Sales oil Reid vapor pressure. 

(vii) Ambient air temperature. 

(viii) Ambient air pressure. 

(2) Determine if the storage tank has 

vapor recovery or thermal control 

devices. 

(i) Adjust the emissions estimated 

using E&P Tank (incorporated by 

reference, see § 98.7) downward by the 

magnitude of emissions captured using 

a vapor recovery system for beneficial 

use. 

(ii) [Reserved] 

(3) Calculate emissions from liquids 

sent to atmospheric storage tanks vented 

to flares as follows: 

(i) Use the storage tank emissions 

volume and gas composition as 

determined in this section. 

(ii) Use the calculation methodology 

of flare stacks in paragraph (n) of this 

section to determine storage tank 

emissions from the flare. 

(4) If liquids are sent to atmospheric 

storage tanks where the tank emissions 

are not represented by the equilibrium 

conditions of the liquid in a gas-liquid 

separator and calculated by E&P Tank 

(incorporate by reference, see § 98.7), 

then emissions shall be calculated as 

follows: 

(i) Use the storage tank emissions as 

determined in this section. 

(ii) Multiply the emissions by 3.87 for 

sales oil less than 45 API gravity. 

(iii) Multiply the emissions by 5.37 

for sales oil equal to or greater than 45 

API gravity. 

(k) Transmission storage tanks. For 

storage tanks without vapor recovery or 

thermal control devices in onshore 

natural gas transmission compression 

facilities calculate annual emissions as 

follows: 

(1) Monitor tank vapor vent stack for 

emissions using an optical gas imaging 

instrument according to methods set 

forth in § 98.234(a)(1) for a duration of 

5 minutes. 

(2) If the tank vapors are continuous 

then use a meter to measure tank 

vapors. 

(i) Use a meter, such as, but not 

limited to a turbine meter, to estimate 

tank vapor volumes according to 

methods set forth in § 98.234(b). 

(ii) Use the appropriate gas 

composition in paragraph (u)(2)(iii) of 

this section. 

(3) Calculate emissions from storage 

tanks to flares as follows: 

(i) Use the storage tank emissions 

volume and gas composition as 

determined in paragraph (j)(1) of this 

section. 

(ii) Use the calculation methodology 

of flare stacks in paragraph (n) of this 

section to determine storage tank 

emissions from the flare. 

(l) Well testing venting and flaring. 

Calculate well testing venting and 

flaring emissions as follows: 

(1) Determine the gas to oil ratio 

(GOR) of the hydrocarbon production 

from each well tested. 


srobinson on DSKHWCL6B1PROD with PROPOSALS3EP12AP10.007</MATH> EP12AP10.008</MATH>
Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 18641 

(i) If GOR is not available then use an 

appropriate standard method published 

by a consensus-based standards 

organization to determine GOR. 

(ii) [Reserved] 

(2) Estimate venting emissions using 

Equation W–11 of this section. 

E GOR FR D a,n = ∗∗ (Eq. W-11)

Where: 

Ea,n = Annual volumetric natural gas 

emissions from well testing in cubic feet 

under ambient conditions. 

GOR = Gas to oil ratio in cubic feet of gas 

per barrel of oil; oil here refers to 

hydrocarbon liquids produced of all API 

gravities. 

FR = Flow rate in barrels of oil per day for 

the well being tested. 

D = Number of days during the year, the well 

is tested. 

(3) Calculate natural gas volumetric 

emissions at standard conditions using 

calculations in paragraph (t) of this 

section. 

(4) Calculate both CH4 and CO2

volumetric and mass emissions from 

volumetric natural gas emissions using 

calculations in paragraphs (u) and (v) of 

this section. 

(5) Calculate emissions from well 

testing to flares as follows: 

(i) Use the well testing emissions 

volume and gas composition as 

determined in paragraphs (l)(1) through 

(3) of this section. 

(ii) Use the calculation methodology 

of flare stacks in paragraph (n) of this 

section to determine well testing 

emissions from the flare. 

(m) Associated gas venting and 

flaring. Calculate associated gas venting 

and flaring emissions as follows: 

(1) Determine the GOR ratio of the 

hydrocarbon production from each well 

whose associated natural gas is vented 

or flared. 

(i) If GOR is not available then use an 

appropriate standard method published 

by a consensus-based standards 

organization to determine GOR. 

(i) [Reserved] 

(2) Estimate venting emissions using 

the Equation W–12 of this section. 

E GOR V a,n = ∗ (Eq. W-12)

Where: 

Ea,n = Annual volumetric natural gas 

emissions from associated gas venting 

under ambient conditions, in cubic feet. 

GOR = Gas to oil ratio in cubic feet of gas 

per barrel of oil; oil here refers to 

hydrocarbon liquids produced of all API 

gravities. 

V = Total volume of oil produced in barrels 

in the reporting year. 

(3) Calculate natural gas volumetric 

emissions at standard conditions using 

calculations in paragraph (t) of this 

section. 

(4) Calculate both CH4 and CO2

volumetric and mass emissions from 

volumetric natural gas emissions using 

calculations in paragraphs (u) and (v) of 

this section. 

(5) Calculate emissions from 

associated natural gas to flares as 

follows: 

(i) Use the associated natural gas 

volume and gas composition as 

determined in paragraphs (m)(1) 

through (3) of this section. 

(ii) Use the calculation methodology 

of flare stacks in paragraph (n) of this 

section to determine associated gas 

emissions from the flare. 

(n) Flare stacks. Calculate emissions 

from a flare stack as follows: 

(1) If you have a continuous flow 

measurement device on the flare, you 

must use the measured flow volumes to 

calculate the flare gas emissions. If you 

do not have a continuous flow 

measurement device on the flare, you 

can install a flow measuring device on 

the flare or use engineering calculations, 

company records, or similar estimates of 

volumetric flare gas flow. 

(2) If you have a continuous gas 

composition analyzer on gas to the flare, 

you must use these compositions in 

calculating emissions. If you do not 

have a continuous gas composition 

analyzer on gas to the flare, you must 

use the appropriate gas compositions for 

each stream of hydrocarbons going to 

the flare as follows: 

(i) When the stream going to the flare 

is natural gas, use the GHG mole percent 

in feed natural gas for all streams 

upstream of the de-methanizer and GHG 

mole percent in facility specific residue 

gas to transmission pipeline systems for 

all emissions sources downstream of the 

de-methanizer overhead for onshore 

natural gas processing facilities. 

(ii) When the stream going to the flare 

is a hydrocarbon product stream, such 

as ethane or butane, then use a 

representative composition from the 

source for the stream. 

(3) Determine flare combustion 

efficiency from manufacturer. If not 

available, assume that flare combustion 

efficiency is 98 percent. 

(4) Calculate GHG volumetric 

emissions at actual conditions using 

Equations W–13, W–14, and W–15 of 

this section. 

E n-c V X a,i a i ( ) () u ombusted = ∗− ∗ 1 η (Eq. W-13)

E combusted V Y R a,CO a j j

j 2 ( ) (Eq. W-14) = ∗∗∗ ∑η

E total E combusted E a,i a,i a,i () ( ) ( ) = + un-combusted (Eq. W-15)

Where: 

Ea,i (un-combusted) = Contribution of annual 

uncombusted GHG i emissions from flare 

stack in cubic feet, under ambient 

conditions. 

Ea,CO2 (combusted) = Contribution of annual 

emissions from combustion from flare 

stack in cubic feet, under ambient 

conditions. 

Ea,I (total) = Total annual emissions from flare 

stack in cubic feet, under ambient 

conditions. 

Va = Volume of natural gas sent to flare in 

cubic feet, during the year. 

h = Percent of natural gas combusted by flare 

(default is 98 percent). 

Xi = Concentration of GHG i in gas to the 

flare. 

Yj = Concentration of natural gas 

hydrocarbon constituents j (such as 

methane, ethane, propane, butane, and 

pentanes plus). 

Rj = Number of carbon atoms in the natural 

gas hydrocarbon constituent j; 1 for 

methane, 2 for ethane, 3 for propane, 4 

for butane, and 5 for pentanes plus). 

(5) Calculate GHG volumetric 

emissions at standard conditions using 

calculations in paragraph (t) of this 

section. 

(6) Calculate both CH4 and CO2 mass 

emissions from volumetric CH4 and CO2

emissions using calculation in 

paragraph (v) of this section. 


srobinson on DSKHWCL6B1PROD with PROPOSALS3EP12AP10.009</MATH> EP12AP10.010</MATH> EP12AP10.011</MATH> EP12AP10.012</MATH> EP12AP10.013</MATH>
18642 Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 

(7) Calculate N2O emissions using the 

emission factors for Gas Flares listed in 

Table W–8 of this subpart. 

(8) This emissions source excludes 

any emissions calculated under other 

emissions sources in § 98.233. 

(o) Centrifugal compressor wet seal 

degassing vents. Calculate emissions 

from centrifugal compressor wet seal 

degassing vents as follows: 

(1) For each centrifugal compressor 

determine the volume of vapors from 

wet seal oil degassing tank sent to an 

atmospheric vent or flare using a 

temporary or permanent flow 

measurement meter such as, but not 

limited to, a vane anemometer 

according to methods set forth in 

§ 98.234(b). 

(2) Estimate annual emissions using 

meter flow measurement using Equation 

W–16 of this section. 

E MT T M B a,i i = ∗∗ ∗− ( ) 1 (Eq. W-16)

Where: 

Ea,i = Annual GHG i (either CH4 or CO2) 

volumetric emissions at ambient 

conditions. 

MT = Meter reading of gas emissions per unit 

time. 

T = Total time the compressor associated 

with the wet seal(s) is operational in the 

reporting year. 

Mi = Mole percent of GHG i in the degassing 

vent gas; use the appropriate gas 

compositions in paragraph (u)(2) of this 

section. 

B = Percentage of centrifugal compressor wet 

seal degassing vent gas sent to vapor 

recovery or fuel gas or other beneficial 

use as determined by keeping logs of the 

number of operating hours for the vapor 

recovery system and the amount of vent 

gas that is directed to the fuel gas system. 

(3) Calculate CH4 and CO2 volumetric 

emissions at standard conditions using 

paragraph (t) of this section. 

(4) Calculate both CH4 and CO2 mass 

emissions from volumetric emissions 

using calculations in paragraph (v) of 

this section. 

(5) Calculate emissions from 

degassing vent vapors to flares as 

follows: 

(i) Use the degassing vent vapor 

volume and gas composition as 

determined in paragraphs (o)(1) through 

(3) of this section. 

(ii) Use the calculation methodology 

of flare stacks in paragraph (n) of this 

section to determine degassing vent 

vapor emissions from the flare. 

(p) Reciprocating compressor rod 

packing venting. Calculate annual CH4

and CO2 emissions from each 

reciprocating compressor rod packing 

venting as follows: 

(1) Estimate annual emissions using a 

meter flow measurement using Equation 

W–17 of this section. 

E MT T M a,i i = ∗∗ (Eq. W-17)

Ea,i = Annual GHG i (either CH4 or CO2) 

volumetric emissions at ambient 

conditions. 

MT = Meter volumetric reading of gas 

emissions per unit time, under ambient 

conditions. 

T = Total time the compressor associated 

with the venting is operational in the 

reporting year. 

Mi = Mole percent of GHG i in the vent gas; 

use the appropriate gas compositions in 

paragraph (u)(2) of this section. 

(2) If the rod packing case is 

connected to an open ended vent line 

then use one of the following two 

methods to calculate emissions. 

(i) Measure emissions from all vents 

(including emissions manifolded to 

common vents) including rod packing, 

unit isolation valves, and blowdown 

valves using bagging according to 

methods set forth in § 98.234(c). 

(ii) Use a temporary meter such as, 

but not limited to, a vane anemometer 

or a permanent meter such as, but not 

limited to, an orifice meter to measure 

emissions from all vents (including 

emissions manifolded to a common 

vent) including rod packing vents, unit 

isolation valves, and blowdown valves 

according to methods set forth in 

§ 98.234(b). 

(3) If the rod packing case is not 

equipped with a vent line use the 

following method to estimate emissions: 

(i) You must use the methods 

described in § 98.234(a) to conduct 

annual leak detection of fugitive 

emissions from the packing case into an 

open distance piece, or from the 

compressor crank case breather cap or 

vent with a closed distance piece. 

(ii) Measure emissions using a high 

flow sampler, or calibrated bag, or 

appropriate meter according to methods 

set forth in § 98.234(d). 

(4) Conduct one measurement for 

each compressor in each of the 

operational modes that occurs during a 

reporting period: 

(i) Operating. 

(ii) Standby pressurized. 

(iii) Not operating, depressurized. 

(5) Calculate CH4 and CO2 volumetric 

emissions at standard conditions using 

calculations in paragraph (t) of this 

section. 

(6) Estimate CH4 and CO2 volumetric 

and mass emissions from volumetric 

natural gas emissions using the 

calculations in paragraphs (u) and (v) of 

this section. 

(q) Leak detection and leaker 

emission factors. You must use the 

methods described in § 98.234(a) to 

conduct an annual leak detection of 

fugitive emissions from all sources 

listed in § 98.232(d)(9), (e)(7), (f)(5), 

(g)(3), (h)(4), and (i)(1). This paragraph 

(q) applies to emissions sources in 

streams with gas content greater than 10 

percent CH4 plus CO2 by weight. 

Emissions sources in streams with gas 

content less than 10 percent CH4 plus 

CO2 by weight do not need to be 

reported. If fugitive emissions are 

detected for sources listed in this 

paragraph, calculate emissions using 

Equation W–18 of this section for each 

source with fugitive emissions. 

E Count EF GHG T s,i i = ∗∗ ∗ (Eq. W-18)

Where: 

Es,i = Annual total volumetric GHG emissions 

at standard conditions from each fugitive 

source. 

Count = Total number of this type of 

emission source found to be leaking. 

EF = Leaker emission factor for specific 

sources listed in Table W–2 through 

Table W–7 of this subpart. 

GHGi = For onshore natural gas processing 

facilities, concentration of GHGi, CH4 or 

CO2, in the total hydrocarbon of the feed 

natural gas; for other facilities listed in 

§ 98.230(a)(3) through (a)(8), GHGi equals 

1. 

T = Total time the specific source associated 

with the fugitive emission was 

operational in the reporting year, in 

hours. 


srobinson on DSKHWCL6B1PROD with PROPOSALS3EP12AP10.014</MATH> EP12AP10.015</MATH> EP12AP10.016</MATH>
Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 18643 

(1) Calculate GHG mass emissions in 

carbon dioxide equivalent at standard 

conditions using calculations in 

paragraph (v) of this section. 

(2) Onshore natural gas processing 

facilities shall use the appropriate 

default leaker emission factors listed in 

Table W–2 of this subpart for fugitive 

emissions detected from valves; 

connectors; open ended lines; pressure 

relief valves; meters; and centrifugal 

compressor dry seals. 

(3) Onshore natural gas transmission 

compression facilities shall use the 

appropriate default leaker emission 

factors listed in Table W–3 of this 

subpart for fugitive emissions detected 

from connectors; block valves; control 

valves; compressor blowdown valves; 

pressure relief valves; orifice meters; 

other meters; regulators; and open 

ended lines. 

(4) Underground natural gas storage 

facilities for storage stations shall use 

the appropriate default leaker emission 

factors listed in Table W–4 of this 

subpart for fugitive emissions detected 

from connectors; block valves; control 

valves; compressor blowdown valves; 

pressure relief valves; orifice meters; 

other meters; regulators; and open 

ended lines. 

(5) LNG storage facilities shall use the 

appropriate default leaker emission 

factors listed in Table W–5 of this 

subpart for fugitive emissions detected 

from valves; pump seals; connectors; 

and other. 

(6) LNG import and export facilities 

shall use the appropriate default leaker 

emission factors listed in Table W–6 of 

this subpart for fugitive emissions 

detected from valves; pump seals; 

connectors; and other. 

(7) Natural gas distribution facilities 

for above ground meter regulator and 

gate stations shall use the appropriate 

default leaker emission factors listed in 

Table W–7 of this subpart for fugitive 

emissions detected from connectors; 

block valves; control valves; pressure 

relief valves; orifice meters; other 

meters; regulators; and open ended 

lines. 

(r) Population count and emission 

factors. This paragraph applies to 

emissions sources listed in 

§ 98.232(c)(2), (c)(9), (c)(15), (c)(21), 

(d)(8), (e)(6), (f)(4), (f)(5), (g)(3), (h)(4), 

(i)(2), (i)(3) and (i)(4), on streams with 

gas content greater than 10 percent CH4

plus CO2 by weight. Emissions sources 

in streams with gas content less than 10 

percent CH4 plus CO2 by weight do not 

need to be reported. Calculate emissions 

from all sources listed in this paragraph 

using Equation W–19 of this section. 

E Count EF GHG T s,i i = ∗∗ ∗ (Eq. W-19)

Es,i = Annual total volumetric GHG 

emissions at standard conditions from each 

fugitive source. 

Count = Total number of this type of 

emission source at the facility. 

EF = Population emission factor for 

specific sources listed in Table W–1 through 

Table W–7 of this subpart. 

GHGi = for onshore petroleum and natural 

gas production facilities and onshore natural 

gas processing facilities, concentration of 

GHG i, CH4 or CO2, in produced natural gas 

or feed natural gas; for other facilities listed 

in § 98.230 (b)(3) through (b)(8),GHGi equals 

1. 

T = Total time the specific source 

associated with the fugitive emission was 

operational in the reporting year, in hours. 

(1) Calculate both CH4 and CO2 mass 

emissions from volumetric emissions 

using calculations in paragraph (v) of 

this section. 

(2) Onshore petroleum and natural gas 

production facilities shall use the 

appropriate default population emission 

factors listed in Table W–1 of this 

subpart for fugitive emissions from 

valves; connectors; open ended lines; 

pressure relief valves; compressor 

starter gas vent; pump; flanges; other; 

and CBM well water production. Where 

facilities conduct EOR operations the 

emissions factor listed in Table W–1 

shall be used to estimate all streams of 

gases, including recycle CO2 stream. In 

cases where the stream is almost all 

CO2, the emissions factors in Table W– 

1 shall be assumed to be for CO2 instead 

of natural gas. 

(3) Onshore natural gas processing 

facilities shall use the appropriate 

default population emission factor listed 

in Table W–2 of this subpart for fugitive 

emissions from gathering pipelines. 

(4) Underground natural gas storage 

facilities for storage wellheads shall use 

the appropriate default population 

emission factors listed in Table W–4 of 

this subpart for fugitive emissions from 

connectors; valves; pressure relief 

valves; and open ended lines. 

(5) LNG storage facilities shall use the 

appropriate default population emission 

factors listed in Table W–5 of this 

subpart for fugitive emissions from 

vapor recovery compressors. 

(6) LNG import and export facilities 

shall use the appropriate default 

population emission factor listed in 

Table W–6 of this subpart for fugitive 

emissions from vapor recovery 

compressors. 

(7) Natural gas distribution facilities 

shall use the appropriate default 

population emission factors listed in 

Table W–7 of this subpart for fugitive 

emissions from below grade M&R 

stations; gathering pipelines; mains; and 

services. 

(s) Offshore petroleum and natural 

gas production facilities in both state 

and federal waters. Report GHG 

emissions from all ‘‘stationary fugitive’’ 

and ‘‘stationary vented’’ sources as 

identified in the Minerals Management 

Service (MMS) Gulfwide Offshore 

Activity Data System (GOADS) study 

(2005 Gulfwide Emission Inventory 

Study MMS 2007–067) for each 

platform. 

(1) MMS GOADS Reporters. Offshore 

production facilities currently reporting 

under the MMS GOADS program will 

report the same annual emissions as 

calculated by GOADS under paragraph 

(s) of this section. 

(i) For the first reporting year, report 

the latest available emissions from 

GOADS. 

(ii) In subsequent reporting years 

when GOADS is updated reporters shall 

report the new emissions that are made 

available from the latest GOADS 

software. 

(ii) For each reporting year that does 

not overlap with the GOADS reporting 

year, report the last reported GOADS 

emissions with emissions adjusted 

based on the operating time for each 

platform. 

(iii) If MMS discontinues or delays 

their GOADS survey by more than 4 

years, then Platform operators shall 

collect monthly activity data every 4 

years from platform sources in 

accordance with the latest version of the 

MMS GOADS program instructions, 

beginning in the year that the GOADS 

survey would have been conducted, and 

annual emissions shall be calculated 

using the latest available MMS GOADS 

emission factors and methods. 

(2) Non-MMS GOADS Reporters. 

Offshore production facilities not 

reporting under the MMS GOADS 

program shall collect monthly activity 

data from platform sources for the first 

reporting year in accordance with the 

latest MMS GOADS program 

instructions. Annual emissions shall be 

calculated using the latest MMS GOADS 

emission factors and methods. 


srobinson on DSKHWCL6B1PROD with PROPOSALS3EP12AP10.017</MATH>
18644 Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 

(i) In subsequent reporting years, 

facilities not reporting under GOADS 

shall follow the data collection cycle as 

GOADS in collecting new activity data 

monthly to estimate emissions and 

report emissions. 

(ii) For each reporting year that does 

not overlap with the GOADS reporting 

year, report the last reported emissions 

data with emissions adjusted based on 

the operating time for each platform. 

(iii) If MMS discontinues or delays 

their GOADS survey by more than 4 

years, then Platform operators shall 

collect monthly activity data every 4 

years from platform sources in 

accordance with the latest version of the 

MMS GOADS program instructions, and 

annual emissions shall be calculated 

using currently available MMS GOADS 

emission factors and methods. 

(t) Volumetric emissions. Calculate 

volumetric emissions at standard 

conditions as specified in paragraphs 

(t)(1) or (2) of this section. 

(1) Calculate natural gas volumetric 

emissions at standard conditions by 

converting ambient temperature and 

pressure of natural gas emissions to 

standard temperature and pressure 

natural gas using Equation W–20 of this 

section. 

E

E TP

T P s,n

a,n s a

a s

= ∗ + ( ) ∗

( ) + ∗

460

460 (Eq. W-20)

Where: 

Es,n = Natural gas volumetric emissions at 

standard temperature and pressure (STP) 

conditions. 

Ea,n = Natural gas volumetric emissions at 

ambient conditions. 

Ts = Temperature at standard conditions. 

(°F). 

Ta = Temperature at actual emission 

conditions. (°F). 

Ps = Absolute pressure at standard conditions 

(inches of Hg). 

Pa = Absolute pressure at ambient conditions 

(inches of Hg). 

(2) Calculate GHG volumetric 

emissions at standard conditions by 

converting ambient temperature and 

pressure of GHG emissions to standard 

temperature and pressure using 

Equation W–21 of this section. 

E

E TP

T P s,i

a,i s a

a s

= ∗ + ( ) ∗

( ) + ∗

460

460 (Eq. W-21)

Where: 

Es,i = GHG i volumetric emissions at 

standard temperature and pressure (STP) 

conditions. 

Ea,i = GHG i volumetric emissions at actual 

conditions. 

Ts = Temperature at standard conditions. 

(°F). 

Ta = Temperature at actual emission 

conditions. (°F). 

Ps = Absolute pressure at standard 

conditions (inches of Hg). 

Pa = Absolute pressure at ambient 

conditions (inches of Hg). 

(u) GHG volumetric emissions. 

Calculate GHG volumetric emissions at 

standard conditions as specified in 

paragraphs (u)(1) and (2) of this section. 

(1) Estimate CH4 and CO2 emissions 

from natural gas emissions using 

Equation W–22 of this section. 

EEM s,i s,n i = ∗ (Eq. W-22)

Where: 

Es,i = GHG i (either CH4 or CO2) volumetric 

emissions at standard conditions. 

Es,n = Natural gas volumetric emissions at 

standard conditions. 

Mi = Mole percent of GHG i in the natural 

gas. 

(2) For Equation W–22 of this section, 

the mole percent, Mi, shall be the 

annual average mole percent for each 

facility, as specified in paragraphs 

(u)(2)(i) through (vii) of this section. 

(i) GHG mole percent in produced 

natural gas for onshore petroleum and 

natural gas production facilities. If you 

have a continuous gas composition 

analyzer for produced natural gas, you 

must use these values in calculating 

emissions. If you do not have a 

continuous gas composition analyzer, 

then quarterly samples must be taken 

according to methods set forth in 

§ 98.234(b). 

(ii) GHG mole percent in feed natural 

gas for all emissions sources upstream 

of the de-methanizer and GHG mole 

percent in facility specific residue gas to 

transmission pipeline systems for all 

emissions sources downstream of the 

de-methanizer overhead for onshore 

natural gas processing facilities. If you 

have a continuous gas composition 

analyzer on feed natural gas, you must 

use these values in calculating 

emissions. If you do not have a 

continuous gas composition analyzer, 

then quarterly samples must be taken 

according to methods set forth in 

§ 98.234(b). 

(iii) GHG mole percent in 

transmission pipeline natural gas that 

passes through the facility for onshore 

natural gas transmission compression 

facilities. 

(iv) GHG mole percent in natural gas 

stored in underground natural gas 

storage facilities. 

(v) GHG mole percent in natural gas 

stored in LNG storage facilities. 

(vi) GHG mole percent in natural gas 

stored in LNG import and export 

facilities. 

(vii) GHG mole percent in local 

distribution pipeline natural gas that 

passes through the facility for natural 

gas distribution facilities. 

(v) GHG mass emissions. Calculate 

GHG mass emissions in carbon dioxide 

equivalent at standard conditions by 

converting the GHG volumetric 

emissions into mass emissions using 

Equation W–23 of this section. 

Mass E GWP s,i s,i i = ∗∗ ∗ − ρ 10 3 (Eq. W-23)

Where: 

Masss,i = GHG i (either CH4 or CO2) mass 

emissions at standard conditions in 

metric tons CO2e. 

Es,i = GHG i (either CH4 or CO2) volumetric 

emissions at standard conditions, in 

cubic feet. 

ri = Density of GHG i, 0.053 kg/ft3 for CO2

and 0.0193 kg/ft3 for CH4. 

GWP = Global warming potential, 1 for CO2

and 21 for CH4. 

(w) EOR injection pump blowdown. 

Calculate pump blowdown emissions as 

follows: 

(1) Calculate the total volume in cubic 

feet (including, but not limited to, 

pipelines, compressors and vessels) 

between isolation valves. 

(2) Retain logs of the number of 

blowdowns per reporting period. 

(3) Calculate the total annual venting 

emissions using Equation W–24 of this 

section: 

Mass N V R GHG c,i v c i =∗∗ ∗ ∗ − 10 3 (Eq. W-24)


srobinson on DSKHWCL6B1PROD with PROPOSALS3EP12AP10.018</MATH> EP12AP10.019</MATH> EP12AP10.020</MATH> EP12AP10.021</MATH> EP12AP10.022</MATH>
Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 18645 

Where: 

Massc,i = Annual EOR injection gas venting 

emissions in metric tons at critical 

conditions ‘‘c’’ from blowdowns. 

N = Number of blowdowns for the equipment 

in reporting year. 

Vv = Total volume in cubic feet of blowdown 

equipment chambers (including, but not 

limited to, pipelines, compressors, 

manifolds and vessels) between isolation 

valves. 

Rc = Density of critical phase EOR injection 

gas in kg/ft3. Use an appropriate 

standard method published by a 

consensus-based standards organization 

to determine density of super critical 

EOR injection gas. 

GHGi = Mass fraction of GHGi in critical 

phase injection gas. 

(x) Hydrocarbon liquids dissolved 

CO2. Calculate dissolved CO2 in 

hydrocarbon liquids as follows: 

(1) Determine the amount of CO2

retained in hydrocarbon liquids after 

flashing in tankage at STP conditions. 

Quarterly samples must be taken 

according to methods set forth in 

§ 98.234(b) to determine retention of 

CO2 in hydrocarbon liquids 

immediately downstream of the storage 

tank. Use the average of the quarterly 

analysis for the reporting period. 

(2) Estimate emissions using Equation 

W–25 of this section. 

Mass S V s hh , CO2 = ∗ (Eq. W-25) 1 1

Where: 

Masss, CO2 = Annual CO2 emissions from CO2

retained in hydrocarbon liquids beyond 

tankage, in metric tons. 

Shl = Amount of CO2 retained in hydrocarbon 

liquids in metric tons per barrel, under 

standard conditions. 

Vhl = Total volume of hydrocarbon liquids 

produced in barrels in the reporting year. 

(y) Produced water dissolved CO2. 

Calculate dissolved CO2 in produced 

water as follows: 

(1) Determine the amount of CO2

retained in produced water at STP 

conditions. Quarterly samples must be 

taken according to methods set forth in 

§ 98.234(b) to determine retention of 

CO2 in produced water immediately 

downstream of the separator where 

hydrocarbon liquids and produced 

water are separated. Use the average of 

the quarterly analysis for the reporting 

period. 

(2) Estimate emissions using the 

Equation W–26 of this section. 

Mass CO Spw Vpw , (Eq. W-26) 2 = ∗

Where: 

Masss, CO2 = Annual CO2 emissions from CO2

retained in produced water beyond 

tankage, in metric tons. 

Spw = Amount of CO2 retained in produced 

water in metric tons per barrel, under 

standard conditions. 

Vpw = Total volume of produced water 

produced in barrels in the reporting year. 

(3) EOR operations that route 

produced water from separation directly 

to re-injection into the hydrocarbon 

reservoir in a closed loop system 

without any leakage to the atmosphere 

are exempt from paragraph (y) of this 

section. 

(z) Portable equipment combustion 

emissions. Calculate emissions from 

portable equipment using the Tier 1 

methodology described in subpart C of 

this part (General Stationary Fuel 

Combustion Sources). 

§ 98.234 Monitoring and QA/QC 

requirements. 

(a) You must use the method 

described as follows to conduct annual 

leak detection of fugitive emissions from 

all source types listed in 

§ 98.233(p)(3)(i) and (q) in operation or 

on standby mode that occur during a 

reporting period. 

(1) Optical gas imaging instrument. 

Use an optical gas imaging instrument 

for fugitive emissions detection in 

accordance with 40 CFR part 60, subpart 

A, § 60.18(i)(1) and (2) Alternative work 

practice for monitoring equipment 

leaks. In addition, you must operate the 

optical gas imaging instrument to image 

the source types required by this 

proposed reporting rule in accordance 

with the instrument manufacturer’s 

operating parameters. 

(2) [Reserved] 

(b) All flow meters, composition 

analyzers and pressure gauges that are 

used to provide data for the GHG 

emissions calculations shall use 

measurement methods, maintenance 

practices, and calibration methods, prior 

to the first reporting year and in each 

subsequent reporting year using an 

appropriate standard method published 

by a consensus standards organization 

such as, but not limited to, ASTM 

International, American National 

Standards Institute (ANSI), and 

American Petroleum Institute (API). If a 

consensus based standard is not 

available, you must use manufacturer 

instructions to calibrate the meters, 

analyzers, and pressure gauges. 

(c) Use calibrated bags (also known as 

vent bags) only where the emissions are 

at near-atmospheric pressures such that 

it is safe to handle and can capture all 

the emissions, below the maximum 

temperature specified by the vent bag 

manufacturer, and the entire emissions 

volume can be encompassed for 

measurement. 

(1) Hold the bag in place enclosing the 

emissions source to capture the entire 

emissions and record the time required 

for completely filling the bag. If the bag 

inflates in less than one second, assume 

one second inflation time. 

(2) Perform three measurements of the 

time required to fill the bag, report the 

emissions as the average of the three 

readings. 

(3) Estimate natural gas volumetric 

emissions at standard conditions using 

calculations in § 98.233(t). 

(4) Estimate CH4 and CO2 volumetric 

and mass emissions from volumetric 

natural gas emissions using the 

calculations in § 98.233(u) and (v). 

(d) Use a high volume sampler to 

measure emissions within the capacity 

of the instrument. 

(1) A technician following 

manufacturer instructions shall conduct 

measurements, including equipment 

manufacturer operating procedures and 

measurement methodologies relevant to 

using a high volume sampler, including, 

but not limited to, positioning the 

instrument for complete capture of the 

fugitive emissions without creating 

backpressure on the source. 

(2) If the high volume sampler, along 

with all attachments available from the 

manufacturer, is not able to capture all 

the emissions from the source then you 

shall use anti-static wraps or other aids 

to capture all emissions without 

violating operating requirements as 

provided in the instrument 

manufacturer’s manual. 

(3) Estimate CH4 and CO2 volumetric 

and mass emissions from volumetric 

natural gas emissions using the 

calculations in § 98.233(u) and (v). 

(4) Calibrate the instrument at 2.5 

percent methane with 97.5 percent air 

and 100 percent CH4 by using calibrated 

gas samples and by following 

manufacturer’s instructions for 

calibration. 

§ 98.235 Procedures for estimating 

missing data. 

A complete record of all estimated 

and/or measured parameters used in the 

GHG emissions calculations is required. 

If data are lost or an error occurs during 

annual emissions estimation or 

measurements, you must repeat the 

estimation or measurement activity for 

those sources as soon as possible, 

including in the subsequent reporting 

year if missing data are not discovered 

until after December 31 of the reporting 

year, until valid data for reporting is 

obtained. Data developed and/or 

collected in a subsequent reporting year 

to substitute for missing data cannot be 

used for that subsequent year’s 

emissions estimation. Where missing 


srobinson on DSKHWCL6B1PROD with PROPOSALS3EP12AP10.023</MATH> EP12AP10.024</MATH>
18646 Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 

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. 

§ 98.236 Data reporting requirements. 

In addition to the information 

required by § 98.3(c), each annual report 

must contain reported emissions as 

specified in this section. 

(a) Report annual emissions 

separately for each of the industry 

segment listed in paragraphs (a) (1) 

through (8) of this section. For each 

segment, report emissions from each 

source type in the aggregate, unless 

specified otherwise. For example, an 

underground natural gas storage 

operation with multiple reciprocating 

compressors must report emissions from 

all reciprocating compressors as an 

aggregate number. 

(1) Onshore petroleum and natural gas 

production. 

(2) Offshore petroleum and natural 

gas production. 

(3) Onshore natural gas processing. 

(4) Onshore natural gas transmission 

compression. 

(5) Underground natural gas storage. 

(6) LNG storage. 

(7) LNG import and export. 

(8) Natural gas distribution. Report 

each source in the aggregate for 

pipelines and for Metering and 

Regulating (M&R) stations. 

(b) Report emissions separately for 

standby equipment. 

(c) Report activity data for each 

aggregated source type as follows: 

(1) Count of natural gas pneumatic 

high bleed devices. 

(2) Count of natural gas pneumatic 

low bleed devices. 

(3) Count of natural gas driven 

pneumatic pumps. 

(4) For each acid gas removal unit 

report the following: 

(i) Total volume of natural gas flow 

into the acid gas removal unit. 

(ii) Total volume of natural gas flow 

out of the acid gas removal unit. 

(iii) Volume weighted CO2 content of 

natural gas into the acid gas removal 

unit. 

(5) For each dehydrator unit report 

the following: 

(i) Glycol dehydrators: 

(A) Glycol dehydrator feed natural gas 

flow rate. 

(B) Glycol dehydrator absorbent 

circulation pump type. 

(C) Glycol dehydrator absorbent 

circulation rate. 

(D) Whether stripper gas is used in 

glycol dehydrator. 

(E) Whether a flash tank separator is 

used in glycol dehydrator. 

(ii) Desiccant dehydrators: 

(A) The number of desiccant 

dehydrators operated. 

(B) [Reserved] 

(6) Count of wells vented to the 

atmosphere for liquids unloading for 

each field in the basin. 

(7) Count of wells venting during well 

completions for each field in the basin. 

(i) Number of conventional 

completions. 

(ii) Number of completions involving 

hydraulic fracturing. 

(8) Count of wells venting during well 

workovers for each field in the basin. 

(i) Number of conventional well 

workovers involving well venting to the 

atmosphere. 

(ii) Number of unconventional well 

workovers involving well venting to the 

atmosphere. 

(9) For each compressor blowdown 

vent stack report the following for each 

compressor: 

(i) Type of compressor whether 

reciprocating or centrifugal. 

(ii) Compressor capacity in horse 

powers. 

(iii) Volume of gas between isolation 

valves. 

(iv) Number of blowdowns per year. 

(10) For each estimate of gas emitted 

from liquids sent to atmospheric tank 

using E&P Tank report the following: 

(i) Immediate upstream separator 

temperature and pressure. 

(ii) Sales oil API gravity. 

(iii) Estimate of individual tank or 

tank battery capacity in barrels. 

(iv) Oil, hydrocarbon condensate and 

water sent to tank(s) in barrels. 

(v) Control measure: Either vapor 

recovery system or flaring of tank 

vapors. 

(11) For tank emissions identified 

using optical gas imaging instrument 

per § 98.234(a), report the following for 

each tank: 

(i) Immediate upstream separator 

temperature and pressure. 

(ii) Sales oil API gravity. 

(iii) Tank capacity in barrels. 

(iv) Tank throughput in barrels. 

(v) Control measure: Either vapor 

recovery system or flaring of tank 

vapors. 

(vi) Optical gas imagining instrument 

used. 

(vii) Meter used for measuring 

emissions. 

(viii) List of emissions sources routed 

to the tank. 

(12) For well testing report the 

following for each field in the basin: 

(i) Number of wells tested in reporting 

period. 

(ii) Average gas to oil ratio for each 

field. 

(iii) Average flow rate during testing 

for each field. 

(iv) Average number of days the well 

is tested. 

(v) Whether the hydrocarbons 

produced during testing are vented or 

flared. 

(13) For associated natural gas venting 

report the following for each field in the 

basin: 

(i) Number of wells venting or flaring 

associated natural gas in reporting 

period. 

(ii) Average gas to oil ratio for each 

field. 

(iii) Average volume of oil produced 

per well per field. 

(iv) Whether the associated natural 

gas is vented or flared. 

(14) For flare stacks report the 

following for each flare: 

(i) Whether flare has a continuous 

flow monitor. 

(ii) If using engineering estimation 

methods, identify sources of emissions 

going to the flare. 

(iii) Whether flare has a continuous 

gas analyzer. 

(iv) Identify proportion of total 

natural gas to pure hydrocarbon stream 

being sent to the flare annually for the 

reporting period. 

(v) Flare combustion efficiency. 

(15) For well venting for liquids 

unloading report the following by field, 

basin, and well tubing size: 

(i) Number of wells being unloaded 

for liquids in reporting year. 

(ii) Average number of unloading(s) 

per well per reporting year. 

(iii) Average volume of natural gas 

produced per well per reporting year 

during liquids unloading. 

(16) For well completions and 

workovers report the following for each 

field in the basin: 

(i) Number of wells completed 

(worked over) in reporting year. 

(ii) Average number of days required 

for completion (workover). 

(iii) Average volume of natural gas 

produced per well per reporting year 

during well completion (workover). 

(17) For compressor wet seal 

degassing vents report the following for 

each degassing vent: 

(i) Number of wet seals connected to 

the degassing vent. 

(ii) Number of compressors whose wet 

seals are connected to the degassing 

vent. 

(iii) Total throughput of compressors 

whose wet seals are connected to the 

degassing vent. 

(iv) Type of meter used for making 

measurements. 

(v) Whether emissions estimate is 

based on a continuous or one time 

measurement. 

(vi) Total time the compressor(s) 

associated with the degassing vent stack 


srobinson on DSKHWCL6B1PROD with PROPOSALS3
Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 18647 

is operating. Sum the hours of operation 

if multiple compressors are connected 

to the vent stack. 

(vii) Proportion of vent gas recovered 

for fuel gas or sent to a flare. 

(18) For reciprocating compressor rod 

packing report the following per rod 

packing: 

(i) Total throughput of the 

reciprocating compressor whose rod 

packing emissions is being reported. 

(ii) Total time in hours the 

reciprocating compressor is in operating 

mode. 

(iii) Whether or not the rod packing 

case is connected to an open ended line. 

(iv) If rod packing is connected to an 

open ended line, report type of device 

used for measurement emissions. 

(v) If rod packing is not connected to 

an open ended vent line, report the 

locations from where the emissions 

from the rod packing are detected. 

(19) For fugitive emissions sources 

using emission factors for estimating 

emissions report the following: 

(i) Component count for each fugitive 

emissions source. 

(ii) CH4 and CO2 in produced natural 

gas for onshore petroleum and natural 

gas production. 

(20) For EOR injection pump 

blowdown report the following per 

pump: 

(i) Pump capacity. 

(ii) Volume of gas between isolation 

valves. 

(iii) Number of blowdowns per year. 

(iv) Supercritical phase EOR injection 

gas density. 

(21) For hydrocarbon liquids 

dissolved CO2 report the following for 

each field in the basin: 

(i) Volume of crude oil produced. 

(ii) [Reserved] 

(22) For produced water dissolved 

CO2 report the following for each field 

in the basin: 

(i) Volume of produced water 

produced. 

(ii) [Reserved] 

(d) Minimum, maximum and average 

throughput for each operation listed in 

paragraphs (a)(1) through (a)(8) of this 

section. 

(e) For offshore petroleum and natural 

gas production facilities, the number of 

connected wells, and whether the wells 

are producing oil, gas, or both. 

(f) Report emissions separately for 

portable equipment for the following 

source types: drilling rigs, dehydrators, 

compressors, electrical generators, 

steam boilers, and heaters. 

(1) Aggregate emissions by source 

type. 

(2) Report count of each source type. 

§ 98.237 Records that must be retained. 

In addition to the information 

required by § 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. 

§ 98.238 Definitions. 

Except as provided below, all terms 

used in this subpart have the same 

meaning given in the Clean Air Act and 

subpart A of this part. 

Natural gas distribution facility means 

the distribution pipelines, metering 

stations, and regulating stations that are 

operated by a Local Distribution 

Company (LDC) that is regulated as a 

separate operating company by a public 

utility commission or that are operated 

as an independent municipally-owned 

distribution system. 

Offshore petroleum and natural gas 

production facility means each platform 

structure and all associated equipment 

as defined in paragraph (a)(1) of this 

section. All production equipment that 

is connected via causeways or walkways 

are one facility. 

Onshore petroleum and natural gas 

production facility means all petroleum 

or natural gas equipment associated 

with all petroleum or natural gas 

production wells under common 

ownership or common control by an 

onshore petroleum and natural gas 

production owner or operator located in 

a single hydrocarbon basin as defined 

by the American Association of 

Petroleum Geologists which is assigned 

a three digit Geologic Province Code. 

Where an operating entity holds more 

than one permit in a basin, then all 

onshore petroleum and natural gas 

production equipment relating to all 

permits in their name in the basin is one 

onshore petroleum and natural gas 

production facility. 

Separator means a vessel in which 

streams of multiple phases are gravity 

separated into individual streams of 

single phase. 

TABLE W–1 OF SUBPART W—DEFAULT WHOLE GAS EMISSION FACTORS FOR ONSHORE PRODUCTION

Onshore production 

Emission Factor 

(scf/hour/component) 

Population Emission Factors—All Components, Gas Service 

Valve ....................................................................................................................................................................................... 0.08 

Connector ............................................................................................................................................................................... 0.01 

Open-ended Line .................................................................................................................................................................... 0.04 

Pressure Relief Valve ............................................................................................................................................................. 0.17 

Low-Bleed Pneumatic Device Vents ...................................................................................................................................... 2.75 

Gathering Pipelines 1 .............................................................................................................................................................. 2.81 

CBM Well Water Production 2 ................................................................................................................................................ 0.11 

Population Emission Factors—All Components, Light Crude Service 3

Valve ....................................................................................................................................................................................... 0.04 

Connector ............................................................................................................................................................................... 0.01 

Open-ended Line .................................................................................................................................................................... 0.04 

Pump ...................................................................................................................................................................................... 0.01 

Other 5 ..................................................................................................................................................................................... 0.24 

Population Emission Factors—All Components, Heavy Crude Service 4

Valve ....................................................................................................................................................................................... 0.001 

Flange ..................................................................................................................................................................................... 0.001 

Connector (other) ................................................................................................................................................................... 0.0004 

Open-ended Line .................................................................................................................................................................... 0.01 

Other 5 ..................................................................................................................................................................................... 0.003 

1Emission Factor is in units of ‘‘scf/hour/mile‘‘. 2Emission Factor is in units of ‘‘scf methane/gallon‘‘, in this case the operating factor is ‘‘gallons/year’’ and do not multiply by methane content. 


srobinson on DSKHWCL6B1PROD with PROPOSALS3
18648 Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 

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

TABLE W–2 OF SUBPART W—DEFAULT TOTAL HYDROCARBON EMISSION FACTORS FOR PROCESSING

Processing 

Before 

de-methanizer 

emission factor 

(scf/hour/component) 

After 

de-methanizer 

emission factor 

(scf/hour/component) 

Leaker Emission Factors—Reciprocating Compressor Components, Gas Service 

Valve ............................................................................................................................................................ 15.88 18.09 

Connector .................................................................................................................................................... 4.31 9.10 

Open-ended Line ......................................................................................................................................... 17.90 10.29 

Pressure Relief Valve .................................................................................................................................. 2.01 30.46 

Meter ............................................................................................................................................................ 0.02 48.29 

Leaker Emission Factors—Centrifugal Compressor Components, Gas Service 

Valve ............................................................................................................................................................ 0.67 2.51 

Connector .................................................................................................................................................... 2.33 3.14 

Open-ended Line ......................................................................................................................................... 17.90 16.17 

Dry Seal ....................................................................................................................................................... 105 105 

Leaker Emission Factors—Other Components, Gas Service 

Valve ............................................................................................................................................................ 6.42 

Connector .................................................................................................................................................... 5.71 

Open-ended Line ......................................................................................................................................... 11.27 

Pressure Relief Valve .................................................................................................................................. 2.01 

Meter ............................................................................................................................................................ 2.93 

Population Emission Factors—Other Components, Gas Service 

Gathering Pipelines 1 ................................................................................................................................... 2.81 

1Emission Factor is in units of ‘‘scf/hour/mile’’. 

TABLE W–3 OF SUBPART W—DEFAULT METHANE EMISSION FACTORS FOR TRANSMISSION

Transmission 

Emission Factor 

(scf/hour/component) 

Leaker Emission Factors—All Components, Gas Service 

Connector ...................................................................................................................................................................................... 2.7 

Block Valve .................................................................................................................................................................................... 10.4 

Control Valve ................................................................................................................................................................................. 3.4 

Compressor Blowdown Valve ........................................................................................................................................................ 543.5 

Pressure Relief Valve .................................................................................................................................................................... 37.2 

Orifice Meter .................................................................................................................................................................................. 14.3 

Other Meter .................................................................................................................................................................................... 0.1 

Regulator ....................................................................................................................................................................................... 9.8 

Open-ended Line ........................................................................................................................................................................... 21.5 

Population Emission Factors—Other Components, Gas Service 

Low-Bleed Pneumatic Device Vents ............................................................................................................................................. 2.57 

TABLE W–4 OF SUBPART W—DEFAULT METHANE EMISSION FACTORS FOR UNDERGROUND STORAGE

Underground storage 

Emission Factor 

(scf/hour/component) 

Leaker Emission Factors—Storage Station, Gas Service 

Connector ...................................................................................................................................................................................... 0.96 

Block Valve .................................................................................................................................................................................... 2.02 

Control Valve ................................................................................................................................................................................. 3.94 

Compressor Blowdown Valve ........................................................................................................................................................ 66.15 

Pressure Relief Valve .................................................................................................................................................................... 19.80 

Orifice Meter .................................................................................................................................................................................. 0.46 


srobinson on DSKHWCL6B1PROD with PROPOSALS3
Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 18649 

TABLE W–4 OF SUBPART W—DEFAULT METHANE EMISSION FACTORS FOR UNDERGROUND STORAGE—Continued 

Underground storage 

Emission Factor 

(scf/hour/component) 

Other Meter .................................................................................................................................................................................... 0.01 

Regulator ....................................................................................................................................................................................... 1.03 

Open-ended Line ........................................................................................................................................................................... 6.01 

Population Emission Factors—Storage Wellheads, Gas Service 

Connector ...................................................................................................................................................................................... 0.01 

Valve .............................................................................................................................................................................................. 0.10 

Pressure Relief Valve .................................................................................................................................................................... 0.17 

Open-ended Line ........................................................................................................................................................................... 0.03 

Population Emission Factors—Other Components, Gas Service 

Low-Bleed Pneumatic Device Vents ............................................................................................................................................. 2.57 

TABLE W–5 OF SUBPART W—DEFAULT METHANE EMISSION FACTORS FOR LIQUEFIED NATURAL GAS (LNG) STORAGE

LNG storage 

Emission Factor 

(scf/hour/component) 

Leaker Emission Factors—LNG Storage Components, LNG Service 

Valve .............................................................................................................................................................................................. 1.19 

Pump Seal ..................................................................................................................................................................................... 4.00 

Connector ...................................................................................................................................................................................... 0.34 

Other1 ............................................................................................................................................................................................ 1.77 

Population Emission Factors—LNG Storage Compressor, Gas Service 

Vapor Recovery Compressor ........................................................................................................................................................ 6.81 

1 ‘‘other’’ equipment type should be applied for any equipment type other than connectors, pumps, or valves. 

TABLE W–6 OF SUBPART W—DEFAULT METHANE EMISSION FACTORS FOR LNG TERMINALS

LNG terminals 

Emission Factor 

(scf/hour/component) 

Leaker Emission Factors—LNG Terminals Components, LNG Service 

Valve .............................................................................................................................................................................................. 1.19 

Pump Seal ..................................................................................................................................................................................... 4.00 

Connector ...................................................................................................................................................................................... 0.34 

Other .............................................................................................................................................................................................. 1.77 

Population Emission Factors—LNG Terminals Compressor, Gas Service 

Vapor Recovery Compressor ........................................................................................................................................................ 6.81 

TABLE W–7 OF SUBPART W—DEFAULT METHANE EMISSION FACTORS FOR DISTRIBUTION

Distribution 

Emission Factor 

(scf/hour/component) 

Leaker Emission Factors—Above Grade M&R Stations Components, Gas Service 

Connector ...................................................................................................................................................................................... 1.69 

Block Valve .................................................................................................................................................................................... 0.557 

Control Valve ................................................................................................................................................................................. 9.34 

Pressure Relief Valve .................................................................................................................................................................... 0.270 

Orifice Meter .................................................................................................................................................................................. 0.212 

Regulator ....................................................................................................................................................................................... 0.772 

Open-ended Line ........................................................................................................................................................................... 26.131 

Population Emission Factors—Below Grade M&R Stations Components, Gas Service 1

Below Grade M&R Station, Inlet Pressure > 300 psig ................................................................................................................. 1.30 


srobinson on DSKHWCL6B1PROD with PROPOSALS3
18650 Federal Register / Vol. 75, No. 69 / Monday, April 12, 2010 / Proposed Rules 

TABLE W–7 OF SUBPART W—DEFAULT METHANE EMISSION FACTORS FOR DISTRIBUTION—Continued 

Distribution 

Emission Factor 

(scf/hour/component) 

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 2

Unprotected Steel .......................................................................................................................................................................... 12.58 

Protected Steel .............................................................................................................................................................................. 0.35 

Plastic ............................................................................................................................................................................................ 1.13 

Cast Iron ........................................................................................................................................................................................ 27.25 

Population Emission Factors—Distribution Services, Gas Service 2

Unprotected Steel .......................................................................................................................................................................... 0.19 

Protected Steel .............................................................................................................................................................................. 0.02 

Plastic ............................................................................................................................................................................................ 0.001 

Copper ........................................................................................................................................................................................... 0.03 

1Emission Factor is in units of ‘‘scf/hour/station‘‘ 2Emission Factor is in units of ‘‘scf/hour/service‘‘ 

TABLE W–8 OF SUBPART W—DEFAULT NITROUS OXIDE EMISSION FACTORS FOR GAS FLARING

Gas Flaring 

Emission Factor 

(metric tons/ 

MMscf gas production or receipts) 

Population Emission Factors—Gas Flaring 

Gas Production .............................................................................................................................................................................. 5.90E–07 

Sweet Gas Processing .................................................................................................................................................................. 7.10E–07 

Sour Gas Processing ..................................................................................................................................................................... 1.50E–06 

Conventional Oil Production 1 ........................................................................................................................................................ 1.00E–04 

Heavy Oil Production 2 ................................................................................................................................................................... 7.30E–05 

1Emission Factor is in units of ‘‘metric tons/barrel conventional oil production‘‘ 2Emission Factor is in units of ‘‘metric tons/barrel heavy oil production‘‘ 

[FR Doc. 2010–6767 Filed 4–9–10; 8:45 am] 

BILLING CODE 6560–50–P 


srobinson on DSKHWCL6B1PROD with PROPOSALS3