Page 1 of 13

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

WASHINGTON, D.C. 20460 

OFFICE OF 

 AIR AND RADIATION 

Petroleum and Natural Gas Systems (Subpart W) of the Greenhouse Gas Reporting Rule 

Docket: EPA-HQ-OAR-2009-0923 

Title: Understanding the Substance of DOT Regulations and Comparing Them to the Subpart W 

Requirements 

Summary: This memorandum discusses the substance of certain regulations of the Department of 

Transportation (DOT), which involve natural gas pipelines and may have had applicability to the 

goals of Subpart W, and compares the content and practices of these regulations with the 

requirements laid out in the requirements of Subpart W. 

 
Page 2 of 13

Understanding the Substance of the DOT Regulations and Comparing Them to the 

Subpart W Requirements 

This memorandum discusses the substance of certain regulations of the Department of 

Transportation (DOT), which involve natural gas pipelines and may have had applicability to the 

goals of Subpart W, and compares the content and practices of these regulations with the 

requirements laid out in the requirements of Subpart W. 

EPA embarked on this detailed review of the DOT regulations based on industry comments 

received in response to the Subpart W proposed regulation. These comments stated that overlap 

already existed in DOT requirements pertaining to local distribution companies (LDCs) that 

would meet the proposed requirements for leak detection and greenhouse gas emissions reporting 

requirements outlined in subpart W. EPA reviewed DOT regulations in an attempt to minimize 

burden and to avoid duplicating existing requirements, if indeed DOT regulations were sufficient 

to EPA’s purposes under Subpart W. 
Page 3 of 13

Background 

In response to the EPA proposed rule addressing GHG emissions from petroleum and natural gas 

systems (subpart W), industry has filed comments requesting that EPA not duplicate and where 

possible align with regulatory requirements already in place under DOT federal leak detection 

regulations with respect to LDCs.

1

 Although both EPA and DOT regulations apply to natural 

gas metering and regulating stations, fundamentally, EPA is concerned with GHG emissions 

detection, measurement and reporting and DOT is focused on safety requirements.2

 

Leak detection for LDCs comes under the reporting requirements of the Pipeline and Hazardous 

Materials Safety Administration (PHMSA). These leak detection requirements focus on the 

concentration (as opposed to the total cumulative volume) of leakage that may be expected over 

the reporting period of one calendar year. Hence the emissions reporting from LDCs for the 

purpose of PHMSA reporting would be expected to be different from that for current Greenhouse 

Gas Mandatory Reporting Rule (MRR) purposes. Nonetheless, there is a potential for overlap, 

which EPA has considered. 

In considering the request, and comparing the substance of the DOT regulations to the Subpart 

W requirements, EPA has examined four criteria: 

1.) What Releases or Leaks are Detected? 

2.) For What Portion of the System is Leak Detection and Quantification Required? 

3.) How Often are Leak Detection and Quantification Conducted? 

4.) How are Leaks Quantified When Detected? 

1. What Releases or Leaks Are Detected? 

In order to determine how the Subpart W regulation overlaps with the DOT leak detection 

regulations, the most important criteria to consider was what each requires the regulated party to 

detect, and whether there is sufficient overlap. The DOT’s Guidance Manual for Operators of 

Small Natural Gas Systems, Chapter IV – Leak Detection (June 2002) (Guidance Manual, 

Chapter IV) provides examples of three grades of releases, classified into categories of leaks; the 

quantifiable example provided is any reading greater than 80% lower explosion limit (LEL) in 

 

1

 DOT’s safety regulations for the transportation of gases by pipeline are published in Title 49 of 

the Code of Federal Regulations (CFR), Parts 190, 191, 192, and 199 and enforced by the Office 

of Pipeline Safety (OPS) of DOT’s Research and Special Programs Administration (RSPA).

2

 DOT’s pipeline safety regulations apply to natural gas systems and operators of natural gas 

master meter systems. The regulations require operators of natural gas systems to (1) deliver gas 

safely and reliably to customers, (2) provide training and written instruction for employees, (3) 

establish written procedures to minimize the hazards resulting from natural gas pipeline 

emergencies, and (4) keep records of inspection and testing.
Page 4 of 13

small gas associated substructures or greater than 20% LEL in a confined space.3 This addresses 

atmospheric concentrations of gas from a general area of the station rather than equipment leak 

emissions from a specific valve or connector. Additionally, gas is odorized under certain 

conditions.4 Odorization may aid in leak detection from the perspective of a safety concern, but 

may not be sufficient to detect all equipment leak emissions.5 Beyond “leak detector equipment” 

the DOT regulations do not specify instrumentation; however, the Guidance Manual, Chapter IV

does indicate that the commonly used leak detector equipment includes the combustible gas 

indictor (CGI) and the flame ionization gas detector (FI). 

Subpart W requires that affected parties detect, calculate, and report equipment leak GHG 

emissions, defined as “those emissions which could not reasonably pass through a stack, 

chimney, vent, or other functionally equivalent opening.” Specifically, Subpart W is concerned 

with above ground meters and regulators at city gate stations at custody transfer, and the 

equipment leak emissions from connectors, block valves, control valves, pressure relief valves, 

orifice meters, regulators, and open ended lines. Further, Subpart W allows the use of several 

leak detection methods including the optical gas imaging instrument; Method 21 (including 

OVA/TVA); or infrared laser beam illuminated instrument. The optical gas imaging instrument 

(also known as an IR camera) and detection methods are defined in the Alternative Work 

Practice for monitoring equipment leaks (AWP)(40 CFR part 60 subpart A §60.18(i)(1) and (2)), 

which is part of the Leak Detection and Repair (LDAR) program. IR cameras are able to scan 

hundreds of source components quickly, including components out of reach for an organic vapor 

analyzer or toxic vapor analyzer (OVA/TVA). The use of OVA/TVA and infrared laser beam 

illuminated leak detection was added to provide flexibility to affected facilities already using 

such instruments. Equipment leak emissions are quantified by applying specific leaker factors to 

the components found leaking with the IR camera, OVA/TVA, or infrared laser beam 

illuminated leak detection. 

 

3 See Guidance Manual, Chapter IV, Table 3a-3c. DOT defines three classes of leaks based on 

LEL readings in a confined space or small structure. Grade 1 (80% LEL and greater) is a leak

that represents an existing or probable hazard to persons or property and requires immediate

repair or continuous action until the conditions are no longer hazardous. Grade 2 (between 20% 

and 80% LEL) is a leak that was non-hazardous at time of detection, but justifies scheduled 

repairs based on probable future hazard. Grade 3 (under 20% LEL) is a leak that is nonhazardous at the time of detection and is reasonably expected to remain non-hazardous. 

4 See 49 CFR 192.625(a) (“A combustible gas in a distribution line must contain a natural 

odorant or be odorized so that at concentration in air of one-fifth of the lower explosive limit, the 

gas is readily datable by a person with a normal sense of smell.”).

5

 In addition to odor, the Guidance Manual, Chapter IV recognizes other methods of detecting a 

leak: (1) improved or deteriorated vegetation in the area; (2) insect activity; (3) fungus-like 

growth in valve boxes and manholes; (3) sound; (4) uncounted for gas determined by meter 

reading; (5) soap solutions; and (6) leak detection equipment. See also 49 CFR § 192.721 

(requiring LDCs to patrol natural gas lines regularly); id. § 192.723 (requiring LDCs to conduct 

leakage surveys with leak detection equipment at regular intervals).
Page 5 of 13

Finding: 

• DOT regulations prescribe detection of releases or leaks from pipeline facilities to 

meet minimum safety requirements. 

• DOT regulations indicate that leaks can be detected, but not necessarily measured or 

emissions reported to DOT, using a variety of methods, including “leak detector 

equipment,” which is not a defined term, but includes CGI and FI. 

• Subpart W requires for LDCs above ground gate stations at custody transfer to detect 

equipment leak GHG emissions from connectors, valves, meters, regulators, and open 

ended lines with an optical gas imaging instrument, OVA/TVA, or infrared laser 

beam illuminated leak detection. 

2. For What Portion of the System Is Leak Detection and Quantification Required? 

The second criterion for comparison between DOT regulations and Subpart W was to determine 

which portions of the distribution system are subject to the requirements of each rule. The DOT 

regulations concerning natural gas transportation apply in scope to pipeline facilities, which 

includes “all facilities through which gas moves in transportation. This includes pipes, valves, 

and other items attached to the pipe, compressor units, meter stations, regulator stations, delivery 

stations, holders, and fabricated assemblies.”6 Subpart W requirements for GHG equipment leak 

emission detection and reporting apply to connectors, valves, meters, regulators, and open ended 

lines at above ground metering and regulating at custody transfer gate stations. 

Finding: 

• DOT leak survey regulations pertain to pipeline facilities, including existing 

pipelines, rights-of-way, and any equipment, facility, or buildings.

• Subpart W leak detection and quantification for LDCs pertains to valves, meters, 

regulators, and open ended lines at above ground metering and regulating stations at 

custody transfer. In the final rule, EPA has clarified that meters and regulators in the 

natural gas distribution industry segment do not include customer meters.

3. How Often Is the Leak Detection and Quantification Conducted? 

The third criterion for comparison between DOT regulations and subpart W is the frequency with 

which leak detection and quantification is conducted. The DOT regulations require leak surveys 

to be conducted at least once per calendar year in business districts and at least once in every five 

calendar years outside of business districts. Per 49 CFR 192: 

§ 192.723 (b) The type and scope of the leakage control program must be determined by 

the nature of the operations and the local conditions, but it must meet the following 

minimum requirements: 

(1) A leakage survey with leak detector equipment must be conducted in business 

districts, including tests of the atmosphere in gas, electric, telephone, sewer, and 

 

6 See 49 CFR 192.3 (definition of “pipeline”).
Page 6 of 13

water system manholes, at cracks in pavement and sidewalks, and at other 

locations providing an opportunity for finding gas leaks, at intervals not 

exceeding 15 months, but at least once each calendar year. 

(2) A leakage survey with leak detector equipment must be conducted outside 

business districts as frequently as necessary, but at least once every 5 calendar 

years at intervals not exceeding 63 months. However, for cathodically 

unprotected distribution lines subject to §192.465(e) on which electrical surveys 

for corrosion are impractical, a leakage survey must be conducted at least once 

every 3 calendar years at intervals not exceeding 39 months. 

DOT does provide that states may adopt more stringent requirements, and some state regulations 

require annual surveys for all sources.7

All affected EPA Subpart W sources are required to detect, calculate, and report GHG equipment 

leak emissions annually, with no provision for less frequent detection in more remote locations 

outside of business districts. 

Finding: 

• DOT leak surveys of distribution systems are required to be conducted every calendar 

year (at intervals not to exceed 15 calendar months) in business districts and every 

five calendar years (at intervals not to exceed 63 months) outside of business districts. 

• Subpart W requires for LDCs above ground gate stations at custody transfer to 

conduct an annual equipment leak detection survey and subsequent emissions 

quantification. 

4. How Are Releases or Leaks Quantified When Detected? 

The fourth criterion for comparison between DOT regulations and Subpart W is methodology for 

quantifying releases or leaks when detected. The DOT regulations do not require quantification 

except in the occurrence of an “incident,” as defined in § 191.3: 

Incident means any of the following events: 

(1) An event that involves a release of gas from a pipeline or of liquefied natural gas 

or gas from an LNG facility and 

(i) A death, or personal injury necessitating in-patient hospitalization; or 

(ii) Estimated property damage, including cost of gas lost, of the operator or others, 

or both, of $50,000 or more. 

(2) An event that results in an emergency shutdown of an LNG facility. 

(3) An event that is significant, in the judgment of the operator, even though it did not 

meet the criteria of paragraphs (1) or (2). 

 

7 See, e.g., Guidance Manual, Chapter I at I-1.
Page 7 of 13

Note that the DOT regulations provide an exemption for reporting releases from an LNG facility 

per §191.9 and §191.11: 

§ 191.9 Distribution system: Incident report. 

 (c) The incident report required by this section need not be submitted with respect to 

master meter systems or LNG facilities. 

§ 191.11 Distribution system: Annual report. 

 (b) The annual report required by this section need not be submitted with 

respect to: (3) LNG facilities. 

Subpart W requires that all equipment leak emissions for LDCs above ground gate stations at 

custody transfer are quantified by applying specific leaker factors to the components found 

leaking during the annual leak detection survey. 

Finding: 

• DOT regulations require quantification of a release of gas from a pipeline that results 

in death, personal injury necessitating hospitalization, estimated property damage 

(including cost of gas lost) exceeding $50,000, or is “significant” in the judgment of 

the operator. 

• Subpart W requires quantification of equipment leak emissions by applying specific 

leaker factors to the connectors, valves, meters, regulators, and open ended lines at 

metering and regulating stations found leaking during the annual leak detection 

survey. 

Summary of Findings: 

• DOT regulations prescribe detection of releases, including leaks from gas pipeline 

facilities, pipeline rights-of-way, and any equipment (including compressors and 

odorization equipment), facility or buildings (including metering and regulating 

stations), used in the transportation or treatment of gas to meet minimum safety 

requirements under 49 CFR 192. 

• Subpart W requires for LDCs above ground gate stations at custody transfer to detect 

and quantify equipment leak GHG emissions from connectors, valves, meters, 

regulators, and open ended lines. 

• DOT regulations indicate that leaks from gas pipeline facilities are to be detected 

using “leak detector equipment,” which is not a defined term within 49 CFR 192. The 

Guidance Manual provides multiple examples of leak detection methods, including 

odor, changes in vegetation, insect activity, fungus growth, sound, unaccounted for 

gas, soap solutions, and leak detection instruments, such as a combustible gas 

indicator (CGI) or flame ionization detector (FI). These instruments do not measure 

actual mass emissions rates of the detected leaks. 

• Subpart W requires that equipment leak GHG emissions from LDCs metering and 

regulating gate stations above ground at custody transfer, detect equipment leak GHG 

emissions using an optical gas imaging instruments, organic vapor analyzers (OVA), 

toxic vapor analyzers (TVA) or infrared laser beam illuminated leak detectors. 
Page 8 of 13

• DOT leak surveys of gas distribution systems including metering and regulating 

stations are required to be conducted every calendar year (at intervals not to exceed 

15 calendar months) in business districts and every five calendar years (at intervals 

not to exceed 63 months) outside of business districts. 

• Subpart W requires for LDCs above ground gate stations at custody transfer to 

conduct an annual equipment leak detection survey and subsequent emissions 

quantification. 

• DOT regulations require quantification of releases resulting from a release of gas 

from a pipeline that results in death, personal injury necessitating hospitalization, 

estimated property damage (including cost of gas lost) exceeding $50,000, or that is 

“significant” in the judgment of the operator. 

• Subpart W requires quantification of equipment leak GHG emissions with an 

OVA/TVA instrument reading equal to or greater than 10,000 ppm, or any emission 

detected by the optical gas imaging instrument or infrared laser beam illuminated 

instrument. Quantification is done by applying specific leaker factors from the 

subpart W rule to the components found leaking. 

Table 1: Terms Defined Under DOT and Subpart W 

Term DOT Regulations Subpart W 

Leak Detection 

Method 

Leaks are to be detected using 

unspecified “leak detector 

equipment.” 

The leak detection options are: 

optical gas imaging 

instrument; Method 21 

(including OVA/TVA); or 

infrared laser beam illuminated 

instrument. 

Release or 

Emissions 

A release is categorized into 

Category 1, 2, or 3 leak. The 

quantifiable description of leak 

per PHMSA is an atmospheric 

gas concentration reading of 

more than 

80% LEL in small gas 

associated substructures or 

more than 20% LEL in a 

confined 

space.8

Method 21 instrument reading 

equal to or greater than 10,000 

ppm. Any emission detected 

by the optical gas imaging 

instrument or infrared laser 

beam illuminated instrument. 

 

8

 See Guidance Manual, Chapter IV, Table 3a-3c. DOT defines three classes of leaks based on 

LEL readings in a confined space or small structure. Grade 1 (80% LEL and greater) is a leak 

that represents an existing or probable hazard to persons or property and requires immediate 

repair or continuous action until the conditions are no longer hazardous. Grade 2 (between 20% 

and 80% LEL) is a leak that was non-hazardous at time of detection, but justifies scheduled
Page 9 of 13

Leak Detection 

Frequency 

Survey interval may range 

from one to five years Annually 

Leak Detection 

Location 

Gas distribution systems 

within business districts and 

outside of business districts 

Above ground gate stations at 

custody transfer at all locations

Leak 

Quantification 

Incidents involving releases 

are quantified if they result in 

death, personal injury 

requiring hospitalization, 

property damage in the 

equivalent of $50,000 

including cost of gas lost, or a 

release deemed “significant” 

by the operator 

Leaks are quantified by 

applying specific leaker factors 

to components found leaking 

during the annual survey 

Equipment Leak 

Emissions Not defined 

Equipment leak means those 

emissions which could not 

reasonably pass through a 

stack, chimney, vent, or other 

functionally equivalent 

opening 

 

repairs based on probable future hazard. Grade 3 (under 20% LEL) is a leak that is nonhazardous at the time of detection and is reasonably expected to remain non-hazardous.
Page 10 of 13

Table 2: Federal Regulations and Federal Guidance Documents Reviewed in 

Comparison of DOT and Subpart W Local Distribution Leak Detection of 

Quantification 

Federal Regulations and 

Federal Guidance 

AGA 

Referenced 

Reviewed 

by EPA 

49 CFR 191 9

49 CFR 192 9 9

49 CFR 192.3 9 9

49 CFR 192.481 9 9

49 CFR 192.613 9 9

49 CFR 192.705 9 9

49 CFR 192.706 9 9

49 CFR 192.721 9 9

49 CFR 192.723 9 9

49 CFR 192.905 9 9

49 CFR 192.921 9 9

49 CFR 192.941 9 9

49 CFR 192.1007 9 9

PHMSA F 7100.1-1 (12-

05) Form Approved OMB 

No. 2137-0522 (Annual 

Reporting Form 

9 9

PHMSA Distribution 

Incident Reporting Form 

F 7100.1 

9 9

PHMSA Transmission 

and Gathering Annual 

Reporting Form F7100.2-

1 

9

PHMSA Transmission 

and Gathering Incident 

Reporting Form F 7100.2 

9

PHMSA Form-02 

Standard Inspection 

Report of a Gas 

Distribution Operator 

9

PHMSA Gas Integrity 

Management Protocol 

Results Form (Jan 2008) 

9
Page 11 of 13

Attachment A 

49 CFR 192 Transportation Of Natural And Other Gas By Pipeline: Minimum Federal Safety 

Standards: Excerpts Related to Leak Surveys in Distribution Systems 

§ 192.1 What is the scope of this part? 

 (a) This part prescribes minimum safety requirements for pipeline facilities and the transportation of gas, including 

pipeline facilities and the transportation of gas within the limits of the outer continental shelf as that term is defined 

in the Outer Continental Shelf Lands Act (43 U.S.C. 1331). 

§ 192.3 Definitions. 

Distribution line means a pipeline other than a gathering or transmission line. 

Pipeline means all parts of those physical facilities through which gas moves in transportation, including pipe, 

valves, and other appurtenance attached to pipe, compressor units, metering stations, regulator stations, delivery 

stations, holders, and fabricated assemblies. 

Pipeline facility means new and existing pipelines, rights-of-way, and any equipment, facility, or building used in 

the transportation of gas or in the treatment of gas during the course of transportation. 

Service line means a distribution line that transports gas from a common source of supply to an individual 

customer, to two adjacent or adjoining residential or small commercial customers, or to multiple residential or 

small commercial customers served through a meter header or manifold. A service line ends at the outlet of the 

customer meter or at the connection to a customer's piping, whichever is further downstream, or at the connection 

to customer piping if there is no meter. 

§ 192.625 Odorization of gas. 

(a) A combustible gas in a distribution line must contain a natural odorant or be odorized so that at a concentration 

in air of one-fifth of the lower explosive limit, the gas is readily detectable by a person with a normal sense of smell.

(b) After December 31, 1976, a combustible gas in a transmission line in a Class 3 or Class 4 location must comply 

with the requirements of paragraph (a) of this section unless:

(1) At least 50 percent of the length of the line downstream from that location is in a Class 1 or Class 2 

location;

(2) The line transports gas to any of the following facilities which received gas without an odorant from that 

line before May 5, 1975;

(i) An underground storage field;

(ii) A gas processing plant;

(iii) A gas dehydration plant; or

(iv) An industrial plant using gas in a process where the presence of an odorant:

(A) Makes the end product unfit for the purpose for which it is intended;

(B) Reduces the activity of a catalyst; or

(C) Reduces the percentage completion of a chemical reaction;

(3) In the case of a lateral line which transports gas to a distribution center, at least 50 percent of the length of 

that line is in a Class 1 or Class 2 location; or

(4) The combustible gas is hydrogen intended for use as a feedstock in a manufacturing process.

(c) In the concentrations in which it is used, the odorant in combustible gases must comply with the following:

(1) The odorant may not be deleterious to persons, materials, or pipe.

(2) The products of combustion from the odorant may not be toxic when breathed nor may they be corrosive or 

harmful to those materials to which the products of combustion will be exposed.

(d) The odorant may not be soluble in water to an extent greater than 2.5 parts to 100 parts by weight.

(e) Equipment for odorization must introduce the odorant without wide variations in the level of odorant.

(f) To assure the proper concentration of odorant in accordance with this section, each operator must conduct 

periodic sampling of combustible gases using an instrument capable of determining the percentage of gas in air at 

which the odor becomes readily detectable. Operators of master meter systems may comply with this requirement 

by—
Page 12 of 13

(1) Receiving written verification from their gas source that the gas has the proper concentration of odorant; 

and

(2) Conducting periodic “sniff” tests at the extremities of the system to confirm that the gas contains odorant.

[35 FR 13257, Aug. 19, 1970]

§ 192.721 Distribution systems: Patrolling. 

 (a) The frequency of patrolling mains must be determined by the severity of the conditions which could cause 

failure or leakage, and the consequent hazards to public safety. 

(b) Mains in places or on structures where anticipated physical movement or external loading could cause failure or 

leakage must be patrolled— 

(1) In business districts, at intervals not exceeding 41/2months, but at least four times each calendar year; and 

(2) Outside business districts, at intervals not exceeding 71/2months, but at least twice each calendar year. 

§ 192.723 Distribution systems: Leakage surveys. 

(a) Each operator of a distribution system shall conduct periodic leakage surveys in accordance with this section. 

(b) The type and scope of the leakage control program must be determined by the nature of the operations and the 

local conditions, but it must meet the following minimum requirements: 

(1) A leakage survey with leak detector equipment must be conducted in business districts, including tests of the 

atmosphere in gas, electric, telephone, sewer, and water system manholes, at cracks in pavement and sidewalks, 

and at other locations providing an opportunity for finding gas leaks, at intervals not exceeding 15 months, but 

at least once each calendar year. 

(2) A leakage survey with leak detector equipment must be conducted outside business districts as frequently as 

necessary, but at least once every 5 calendar years at intervals not exceeding 63 months. However, for 

cathodically unprotected distribution lines subject to §192.465(e) on which electrical surveys for corrosion are 

impractical, a leakage survey must be conducted at least once every 3 calendar years at intervals not exceeding 

39 months. 

 § 192.703 General. 

 (c) Hazardous leaks must be repaired promptly. 

§ 192.1001 

Hazardous Leak means a leak that represents an existing or probable hazard to persons or property and requires 

immediate repair or continuous action until the conditions are no longer hazardous. 
Page 13 of 13

Attachment B 

49 CFR 191 Transportation Of Natural And Other Gas By Pipeline: Annual Reports, Incident 

Reports, and Safety Related Condition Reports: Excerpts Related to Leak Surveys in 

Distribution Systems 

§ 191.3 Definitions. 

As used in this part and the PHMSA Forms referenced in this part— 

Gas means natural gas, flammable gas, or gas which is toxic or corrosive; 

Incident means any of the following events: 

(1) An event that involves a release of gas from a pipeline or of liquefied natural gas or gas from an LNG 

facility and 

(i) A death, or personal injury necessitating in-patient hospitalization; or 

(ii) Estimated property damage, including cost of gas lost, of the operator or others, or both, of $50,000 or 

more. 

(2) An event that results in an emergency shutdown of an LNG facility. 

(3) An event that is significant, in the judgment of the operator, even though it did not meet the criteria of 

paragraphs (1) or (2). 

§ 191.9 Distribution system: Incident report. 

 (c) The incident report required by this section need not be submitted with respect to master meter systems or LNG 

facilities. 

§ 191.11 Distribution system: Annual report. 

 (b) The annual report required by this section need not be submitted with respect to: (3) LNG facilities.