Federal Register / Vol. 73, No. 123 / Wednesday, June 25, 2008 / Proposed Rules 36015 

509.403 Definitions. 

Debarring official means the 

Suspension and Debarment Official 

within the Office of the Chief 

Acquisition Officer. 

* * * * * 

Suspending official means the 

Suspension and Debarment Official 

within the Office of the Chief 

Acquisition Officer. 

9. Revise section 509.405 to read as 

follows: 

509.405 Effect of listing. 

509.405–1 Continuation of current 

contracts. 

(a) When a contractor appears on the 

current EPLS, consider terminating a 

contract under any of the following 

circumstances: 

(1) Any circumstances giving rise to 

the debarment or suspension also 

constitute a default in the contractor’s 

performance of the contract. 

(2) The contractor presents a 

significant risk to the Government in 

completing the contract. 

(3) The conduct that provides the 

cause of the suspension, proposed 

debarment, or debarment involved a 

GSA contract. 

(b) Before terminating a contract when 

a contractor appears on the current 

EPLS, consider the following factors: 

(1) Seriousness of the cause for 

debarment or suspension. 

(2) Extent of contract performance. 

(3) Potential costs of termination and 

reprocurement. 

(4) Need for or urgency of the 

requirement, contract coverage, and the 

impact of delay for reprocurement. 

(5) Availability of other safeguards to 

protect the Government’s interest until 

completion of the contract. 

(6) Availability of alternate 

competitive sources to meet the 

requirement (e.g., other multiple award 

contracts, readily available commercial 

items). 

(c) The responsibilities of the agency 

head under FAR 9.405–1 are delegated 

to the GSA Suspension and Debarment 

Official. 

509.405–2 Restrictions on subcontracting. 

The responsibilities of the agency 

head under FAR 9.405–2(a) are 

delegated to the GSA Suspension and 

Debarment Official. 

10. Revise section 509.406–1 to read 

as follows: 

509.406–1 General. 

The Suspension and Debarment 

Official is the designee under FAR 

9.406–1(c). 

11. Amend section 509.406–3 by—

a. Removing from paragraphs (a) and 

(b), the words ‘‘debarring official’’ and 

adding the words ‘‘Suspension and 

Debarment Official’’ in its place each 

time it appears; 

b. Removing from paragraph (b)(2), 

the word ‘‘Number’’ and adding the 

word ‘‘Numbers’’ in its place; 

c. Removing paragraph (b)(7); 

d. Revising paragraph (c); and 

e. Removing from paragraph (d), the 

words ‘‘debarring official’’ and adding 

the words ‘‘Suspension and Debarment 

Official’’ in its place each time it 

appears. 

The revised text reads as follows: 

509.406–3 Procedures. 

* * * * * 

(c) Review. The Suspension and 

Debarment Official will review the 

report, and after coordinating with 

assigned legal counsel—

(1) Initiate debarment action; 

(2) Decline debarment action; 

(3) Request additional information; or 

(4) Refer the matter to the OIG for 

further investigation and development 

of a case file. 

* * * * * 

509.407–1 [Amended] 

12. Amend section 509.407–1 by 

removing the words ‘‘suspending 

official’’ and adding ‘‘Suspension and 

Debarment Official’’ in its place. 

509.407–3 [Amended] 

13. Amend section 509.407–3 by 

removing the words ‘‘suspending 

official’’ and adding ‘‘Suspension and 

Debarment Official’’ in its place each 

time it appears. 

PART 552—SOLICITATION 

PROVISIONS AND CONTRACT 

CLAUSES 

552.209–70 through 552.209–73 

[Removed] 

14. Sections 552.209–70 through 

552.209–73 are removed. 

[FR Doc. E8–14392 Filed 6–24–08; 8:45 am] 

BILLING CODE 6820–61–S 

DEPARTMENT OF TRANSPORTATION 

Pipeline and Hazardous Materials 

Safety Administration 

49 CFR Part 192 

[Docket No. PHMSA–RSPA–2004–19854] 

RIN 2137–AE15 

Pipeline Safety: Integrity Management 

Program for Gas Distribution Pipelines 

AGENCY: Pipeline and Hazardous 

Materials Safety Administration 

(PHMSA), Department of Transportation 

(DOT). 

ACTION: Notice of proposed rulemaking. 

SUMMARY: PHMSA proposes to amend 

the Federal Pipeline Safety Regulations 

to require operators of gas distribution 

pipelines to develop and implement 

integrity management (IM) programs. 

The purpose of these programs is to 

enhance safety by identifying and 

reducing pipeline integrity risks. The IM 

programs required by the proposed rule 

would be similar to those currently 

required for gas transmission pipelines, 

but tailored to reflect the differences in 

and among distribution systems. In 

accordance with Federal law, the 

proposed rule would require operators 

to install excess flow valves on certain 

new and replaced residential service 

lines, subject to feasibility criteria 

outlined in the rule. Based on the 

required risk assessments and enhanced 

controls, the proposed rule also would 

establish procedures and standards 

permitting risk-based adjustment of 

prescribed intervals for leak detection 

surveys and other fixed-interval 

requirements in the agency’s existing 

regulations for gas distribution 

pipelines. To further minimize 

regulatory burdens, the proposed rule 

would establish simpler requirements 

for master meter and liquefied 

petroleum gas (LPG) operators, 

reflecting the relatively lower risk of 

these small pipeline systems. 

This proposal also addresses statutory 

mandates and recommendations from 

the DOT’s Office of the Inspector 

General (OIG) and stakeholder groups. 

DATES: Anyone may submit written 

comments on proposed regulatory 

changes by September 23, 2008. PHMSA 

will consider late-filed comments to the 

extent possible. 

ADDRESSES: Comments should reference 

Docket No. PHMSA–RSPA–2004–19854 

and may be submitted in the following 

ways: 

• E-Gov Web Site: http:// 

www.regulations.gov. This site allows 

the public to enter comments on any 

Federal Register notice issued by any 

agency. 

• Fax: 1–202–493–2251. 

• Mail: DOT Docket Operations 

Facility (M–30), U.S. Department of 

Transportation, West Building, 1200 

New Jersey Avenue SE., Washington, 

DC 20590. 

• Hand Delivery: DOT Docket 

Operations Facility, U.S. Department of 

Transportation, West Building, Room 

W12–140, 1200 New Jersey Avenue SE., 

Washington, DC 20590 between 9 a.m. 

and 5 p.m., Monday through Friday, 

except Federal holidays. 

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36016 Federal Register / Vol. 73, No. 123 / Wednesday, June 25, 2008 / Proposed Rules 

Instructions: In the E-Gov Web site: 

http://www.regulations.gov, under 

‘‘Search Documents’’ select ‘‘Pipeline 

and Hazardous Materials Safety 

Administration.’’ Next, select ‘‘Notices,’’

and then click ‘‘Submit.’’ Select this 

rulemaking by clicking on the docket 

number listed above. Submit your 

comment by clicking the yellow bubble 

in the right column then following the 

instructions. 

Identify docket number PHMSA–

RSPA–2004–19854 at the beginning of 

your comments. For comments by mail, 

please provide two copies. To receive 

PHMSA’s confirmation receipt, include 

a self-addressed stamped postcard. 

Internet users may access all comments 

at http://www.regulations.gov, by 

following the steps above. 

Note: PHMSA will post all comments 

without changes or edits to http:// 

www.regulations.gov including any personal 

information provided. 

Privacy Act Statement 

Anyone can search the electronic 

form of all comments received in 

response to any of our dockets by the 

name of the individual submitting the 

comment (or signing the comment, if 

submitted on behalf of an association, 

business, labor union, etc.). DOT’s 

complete Privacy Act Statement was 

published in the Federal Register on 

April 11, 2000 (65 FR 19477). 

FOR FURTHER INFORMATION CONTACT: 

Mike Israni at (202) 366–4571 or by 

e-mail at mike.israni@dot.gov. 

SUPPLEMENTARY INFORMATION: The 

following subjects are addressed in this 

preamble: 

I. Background 

A. Integrity Management (IM) 

B. Nature of U.S. Distribution Pipeline 

Systems 

C. Safety of Distribution Pipeline Systems 

D. Distribution Pipeline Safety Regulation 

E. Applicability of Integrity Management 

Plans (IMP) to Distribution Pipeline 

Systems 

Distribution Systems Are Located in 

Highly Populated Areas 

Challenges of Assessment or Testing 

II. American Gas Foundation Study 

III. Recommendations or Mandates of 

Oversight Bodies 

A. DOT Inspector General 

B. National Transportation Safety Board 

C. Congressional Mandate 

IV. Stakeholder Groups 

A. Stakeholder Groups’ Involvement 

B. Stakeholder Groups’ Findings 

C. Stakeholder Conclusions 

D. Findings Relevant To Leak Management 

E. Stakeholder Considerations Regarding 

Excess Flow Valves Comments From Fire 

Service Organizations 

V. Public Meetings 

A. Public Meetings Concerning 

Distribution Integrity Management 

B. EFV Public Meeting 

VI. Guidance for Integrity Management 

VII. Applicability to Small and Simple 

Distribution Systems; Request for 

Comments 

A. Master Meter and LPG Operators 

B. Very Small Distribution Systems 

VIII. Plastic Pipe Issues 

A. Plastic Pipeline Database and 

Availability of Failure Information 

B. Plastic Pipe Marking 

IX. Monitoring the Effectiveness of Actions 

X. Deviating From Required Intervals Based 

on Operator’s Distribution Integrity 

Management Plan (DIMP) 

XI. Prevention Through People 

XII. Summary Description of Proposed Rule 

XIII. Section-by-Section Analysis 

XIV. Regulatory Analyses and Notices 

I. Background 

A. Integrity Management 

PHMSA is initiating this rulemaking 

proceeding in order to extend its 

integrity management approach to the 

largest segment of the Nation’s pipeline 

network—the distribution systems that 

directly serve homes, schools, 

businesses, and other natural gas 

consumers. Beginning in 2000, the 

agency has promulgated regulations 

requiring operators of hazardous liquid 

pipelines (49 CFR 195.452, published at 

65 FR 75378 and 67 FR 2136) and gas 

transmission pipelines (49 CFR 192, 

Subpart O, published at 68 FR 69778) to 

develop and follow individualized 

integrity management (IM) programs, in 

addition to PHMSA’s core pipeline 

safety regulations. The IM approach was 

designed to promote continuous 

improvement in pipeline safety by 

requiring operators to identify and 

invest in risk control measures beyond 

core regulatory requirements. 

The IM regulations for hazardous 

liquid and gas transmission pipelines 

are similar. Fundamentally, both require 

that operators analyze their pipelines to 

identify and manage factors that affect 

risks to the pipeline and risks posed by 

the pipeline. Operators must integrate 

the best available information about 

their pipelines to inform their risk 

decisions. Both rules require that 

operators identify segments of their 

pipelines where an incident could cause 

serious consequences and focus priority 

attention in those areas. Both rules also 

require that operators implement a 

program to provide greater assurance of 

the integrity of these pipeline segments. 

Actions required in these segments 

include assessments utilizing in-line 

inspection tools, pressure testing, direct 

assessment, or other technology that 

provides an equivalent understanding of 

the pipe condition. While existing 

regulations required prompt repair of 

safety-significant problems, the IM 

regulations require operators to inspect 

their lines and perform repairs within a 

period of time commensurate with the 

safety significance of the problems 

found. The rules also require that 

operators implement measures that will 

help prevent accidents from occurring 

on their high-consequence segments and 

that will mitigate the consequences if an 

accident does occur. 

Although it is too early to draw 

statistically-significant conclusions 

about the effectiveness of the IM 

programs for transmission pipelines, 

early indications are very favorable. The 

initial inspections under IM have 

identified tens of thousands of locations 

where the pipelines were damaged 

(including damage by external force/ 

excavation and by conditions like 

corrosion) and repairs were made before 

accidents could occur. Operators have 

implemented additional safety measures 

to address higher-risk situations, many 

of which are unique to their individual 

circumstances. These early successes 

have fueled interest in extending the IM 

approach to gas distribution pipeline 

systems. 

B. Nature of U.S. Distribution Pipeline 

Systems 

As of 2006, more than 1.2 million 

miles of gas mains are in service in the 

U.S. ‘‘Mains’’ are the pipelines 

providing a common supply to a certain 

number (often hundreds) of homes and 

businesses. These pipelines are often 

located under city streets and range in 

size from less than 2 inches in diameter 

to more than 8 inches in diameter. 

These mains feed over 63 million 

‘‘services.’’ A ‘‘service’’ is the pipe that 

connects to a main and delivers gas to 

an individual customer, at the meter. 

Service lines are usually very small, less 

than 1-inch in diameter except for those 

serving larger industrial and commercial 

customers. The length of service lines 

varies widely. In dense urban areas 

where townhouses are built right up to 

the sidewalk, a service line may be only 

a few feet long. In rural areas, service 

lines may be several hundred feet long, 

perhaps as long as a mile. PHMSA uses 

65 feet as its estimate of the average 

length of a service line. Applying that 

value, the 63 million services represent 

nearly another 800,000 miles of 

pipeline, meaning that the total amount 

of pipeline in U.S. distribution pipeline 

systems is approximately two million 

miles. Use of natural gas continues to 

grow in the U.S., and the amount of 

distribution pipeline in service 

increases accordingly. Since 2001, an 

additional 5.1 million customers have 

been added, representing an increase of 

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1Some of these programs involve a limited 

number of operators, as described further below. 

2NAPSR’s members are the managers of the 

pipeline safety regulatory staff from each state (and 

the District of Columbia) that is certified by, or a 

designated agent of, DOT for regulatory oversight. 

3NAPSR conducted the survey in 2004–2005. 

over 173,000 miles of distribution 

pipeline. 

Natural gas has been distributed by 

pipeline in some areas for over a 

hundred years. Pipeline systems in 

these areas were originally small, 

serving a few customers. These systems 

often merged as larger distribution 

companies were formed. The materials 

in use in some of these systems reflect 

older (e.g., cast iron, copper, bare steel) 

as well as newer (e.g., polyethylene 

plastic and cathodically-protected 

coated steel) technologies. Two-thirds of 

States have programs that require 

distribution pipeline operators to 

replace older pipe,1 but much of the 

pipe in service is still many decades 

old. 

In other areas, distribution of natural 

gas by pipeline is a relatively new 

phenomenon. In some rural areas, for 

example, gas may not have been 

available until a transmission pipeline 

was routed into the vicinity. Then, 

municipalities or distribution 

companies may have created a 

distribution system to bring natural gas 

service to customers for whom it was 

previously unavailable. Systems of this 

nature tend to be relatively uniform in 

age and type of materials, but the threats 

to integrity (such as electrical 

interference from other buried 

substructures and localized flooding or 

vehicular traffic patterns) may still vary 

from one location to another. Diversity 

of the gas pipeline system will likely 

increase as systems age, new customers 

are added, and portions of the original 

systems are replaced. The bulk of newer 

gas distribution pipeline systems, and 

replacements for older pipe, are 

comprised of plastic pipe. More than 

half of the pipelines in U.S. gas 

distribution systems are non-metallic. 

C. Safety of Distribution Pipeline 

Systems 

By operation of the Federal Pipeline 

Safety Laws, 49 U.S.C. 60102, the 

Federal government has assumed 

ultimate responsibility for the safety 

oversight of distribution pipeline 

operators. PHMSA’s regulations in 49 

CFR Part 192 establish a minimum set 

of safety requirements that all States 

must implement, although States may 

impose more stringent requirements on 

intrastate systems. PHMSA also collects 

data concerning distribution system 

mileage, incidents that occur on 

distribution systems, their leak repair 

experience and other information about 

the size, age and material(s) of 

construction of their distribution piping. 

PHMSA considered this information, its 

historical trends, and projected patterns 

in proposing IM regulations for 

distribution pipelines. 

Incidents on distribution pipelines 

kill and injure more people than 

incidents on gas transmission pipelines. 

As noted above, nearly two million 

miles of distribution pipelines are in 

operation in the U.S., compared with 

approximately 300,000 miles of gas 

transmission pipelines. In addition, 

distribution pipelines are almost all 

located in populated areas. Large 

portions of gas transmission pipelines 

traverse rural areas where there are few 

people. Largely because of these 

differences, incidents on distribution 

pipelines in 2006 resulted in five times 

as many fatalities (16 vs. 3) and six 

times as many serious injuries (25 vs. 4) 

as those on gas transmission pipelines, 

even though the total number of 

incidents on each type of pipeline was 

about the same (141 vs. 134). Because of 

the much larger number of miles of 

distribution pipeline, the normalized 

rate of fatalities and injuries (i.e., the 

number per 100,000 miles) is similar for 

the two types of lines, with a slightly 

lower rate for distribution lines. As 

described further below, the trend in gas 

distribution incidents involving 

fatalities and serious injuries (those 

requiring hospitalization) was 

downward from 1990–2002. In the years 

since, however, the number has again 

started to increase. 

D. Distribution Pipeline Safety 

Regulation 

Pursuant to Federal law, most 

oversight of gas distribution pipeline 

systems is performed directly by States. 

Under 49 U.S.C. 60105 and 60106, a 

State may exercise jurisdiction over 

intrastate gas distribution operations 

within the State if its pipeline safety 

program is certified by PHMSA or if it 

enters into an agency agreement with 

DOT. Under these provisions, 48 States 

(excluding only Alaska and Hawaii) and 

the District of Columbia currently 

exercise safety jurisdiction over some or 

all gas distribution operations within 

their boundaries. States must implement 

the minimum standards established by 

PHMSA but have a variety of ways in 

which they can oversee distribution 

pipeline safety. They can simply mirror 

the Federal pipeline safety program; 

they can impose additional 

requirements, beyond the Federal 

minimum; they can engage in special 

oversight programs with individual 

operators or groups of operators; or 

finally, they can provide incentives for 

safety improvements, often through 

their rate-setting authority. 

It is appropriate that the principal 

actions for regulating distribution 

pipeline safety rest with the States. 

States need to balance safety and 

affordability. They need to ensure that 

the particular needs of their citizenry 

are fulfilled. They also need to ensure 

that the applied safety standards are 

appropriate for the unique environment 

in which gas distribution occurs. 

Distribution pipeline systems are 

limited in geographic scope, although 

some systems serve many thousands of 

customers. The environment in which 

they operate significantly affects the 

safety issues that they face. Factors such 

as weather (dry/wet, hot/subject to 

freezing), soil conditions (corrosivity), 

and the local economy (significant 

construction and excavation activity) 

can significantly shape the threats 

affecting individual distribution 

operators and the actions necessary to 

address those threats. Proximity to gasproducing regions also can be 

important, as natural gas that is 

distributed near production areas may 

be subject to less processing and may 

contain more contaminants, with greater 

potential to affect system integrity, than 

gas that is processed for long-distance 

transportation. 

States must have flexibility to deal 

with their local circumstances. It would 

be both ineffective and inefficient, for 

example, to impose frost heave damage 

requirements in the desert southwest. 

States address these differences by 

imposing some requirements that 

exceed those in the Federal safety code. 

The National Association of Pipeline 

Safety Representatives (NAPSR)2

surveyed its members to determine the 

extent to which they impose 

requirements or programs that exceed 

the Federal minimum.3 The survey, 

addressed to each State pipeline safety 

program manager, asked whether the 

State imposes additional requirements 

or has infrastructure safety 

improvement programs implemented 

that exceed the federal minimum 

requirements. NAPSR asked its 

members to provide a brief description 

of any positive responses. 

Forty-eight State agencies and the 

District of Columbia responded to the 

NAPSR survey. All but six reported 

some requirements or programs 

exceeding the Federal minimum 

standards. The results were as follows: 

• 20 States have additional reporting 

requirements; 

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36018 Federal Register / Vol. 73, No. 123 / Wednesday, June 25, 2008 / Proposed Rules 

• 11 States provide enhanced 

oversight and observation of work/ 

testing on the pipelines; 

• 11 States have additional damage 

prevention requirements; 

• 13 States require additional leak 

testing; 

• 11 States impose leak response 

requirements (including eight of the 13 

that require additional leak testing); 

• Eight States impose either 

additional odorant requirements or 

more frequent testing; 

• Six States impose additional design 

and installation requirements; 

• Six States impose additional 

training and qualification of operator 

personnel requirements. 

• Six States impose additional 

requirements related to cathodic 

protection systems used to protect steel 

pipe from corrosion; 

• Six States require their State 

regulators to approve operators’

operating and maintenance plans; 

• Five States impose operating 

pressure requirements; 

• Five States impose additional 

customer meter requirements; 

• Three States require that operators 

cap off abandoned service lines after 

specified periods; 

• Four States extend operator 

responsibility for maintenance of 

service/customer lines; 

• Four States encourage safety 

enhancement through rate cases, and 

approve the operation of distribution 

pipeline systems by specific companies; 

• One State requires its operators to 

conduct an annual evaluation of all cast 

iron and unprotected steel pipe in their 

distribution systems; and 

• One State requires its operators to 

remediate any evidence found of 

corrosion within 90 days. 

The most significant area in which 

States reported actions beyond Federal 

standards was replacement of aging and 

inferior infrastructure. Thirty-three 

States, or two-thirds of those 

responding, reported they have some 

kind of program for replacing 

infrastructure, including cast-iron pipe, 

uncoated steel pipe, copper pipe, and 

some types of plastic pipe. These 

programs varied in scope and schedule, 

often reflecting the relative amount of 

targeted infrastructure present in each 

State. NAPSR collected the following 

data on pipe replacement programs: 

• Twelve States reported their 

programs involved all (or nearly all) 

operators; 

• Sixteen States reported their 

programs involved one or a limited 

number of operators, often in response 

to past accidents or rate cases; 

• Four States provided no 

information from which to estimate the 

scope of their programs; 

• Eight States reported that their 

programs are complete (i.e., all targeted 

infrastructure has been replaced) or will 

be completed by 2010; 

• Eight States reported that their 

programs will be complete by about 

2020; 

• Four States reported that their 

programs would not be complete until 

after 2020; and 

• Twelve States did not report an 

expected completion date. 

These results indicate States can and do 

exercise authority beyond minimum 

Federal requirements. Additional 

requirements are focused in scope, and 

vary from State to State, based on local 

needs and issues. Programs to replace 

older, inferior infrastructure are the 

most widespread practice beyond 

Federal requirements. Such programs 

are in progress in two-thirds of the 

States, although some of these programs 

are of limited scope (i.e., affecting a 

single operator). 

Still, despite these State efforts, 

serious incidents continue to occur on 

distribution pipeline systems. As 

discussed above, the number of serious 

incidents per mile is similar to that for 

gas transmission pipelines, but there are 

many more miles of distribution 

pipelines. As a result, serious incidents 

on gas distribution pipelines kill or 

injure more people annually than do 

incidents on gas transmission pipelines. 

Even if the number of serious incidents 

on transmission pipelines is 

significantly reduced, major 

improvement in overall safety will not 

be achieved unless the number of 

incidents on distribution pipelines is 

also reduced. PHMSA’s approach to 

achieving improvement for gas 

transmission pipelines was to require 

that each operator analyze its own 

pipeline’s risks, through an integrity 

management program, and address them 

as necessary. PHMSA concludes that the 

same approach is appropriate for 

distribution pipelines. 

Although the additional State 

requirements provide protection beyond 

the minimum Federal standards to help 

assure the integrity of distribution 

pipeline systems, the requirements vary 

by State. No State requires a 

comprehensive systematic evaluation 

and management of the risks associated 

with operating gas distribution 

pipelines similar to PHMSA’s existing 

IM requirements or to the requirements 

we are proposing in this Notice. 

Nevertheless, some State imposed 

requirements likely encompass 

individual actions operators would be 

required to take under an IM program, 

offsetting the costs for those operators to 

comply with this rule. 

The National Association of 

Regulatory Utility Commissioners 

(NARUC) has also considered the need 

for additional safety regulation. NARUC 

members represent Public Service/ 

Safety Commissions under whose 

auspices States usually conduct 

pipeline safety regulatory programs. As 

such, NARUC represents executive 

management of State pipeline safety 

programs. In February 2005, the NARUC 

Board of Directors adopted a resolution 

encouraging development of an 

approach to distribution IM using riskbased, technically-sound, and costeffective performance-based measures. 

NARUC recommended an approach 

based on the notion that operators are 

knowledgeable about their 

infrastructure and can identify and 

respond to threats against their systems 

in order to reduce the risk of system 

failures while balancing the need to 

ensure continued safe, reliable service at 

a minimal financial cost. 

NARUC based its resolution on the 

long-standing commitment of industry 

and government to operate the United 

States’ gas pipeline system reliably and 

safely. They acknowledged recent 

examinations by regulators, legislators, 

and gas distribution pipeline operators 

to determine the most effective 

approach to maintaining and enhancing 

distribution system integrity and safety. 

NARUC commented that States must 

take into account varying circumstances 

including: geography, energy customer 

base, local economy, system age and 

construction materials, size of 

distribution operations and 

consumption patterns of gas customers 

(ranging from large-volume 

manufacturers to mid-size businesses to 

single-family residences), as well as a 

State’s overall executive policies and 

goals. 

NARUC noted that due to significant 

structural, geographical, and functional 

differences among gas transmission and 

distribution companies, it would be 

infeasible to apply many transmission 

integrity requirements to distribution 

systems. NARUC further noted any 

adjustment to an operator’s distribution 

IM program should be responsive to the 

operator’s safety performance, existing 

regulations, and current practices 

affecting such performance. 

E. Applicability of Integrity Management 

Plans (IMP) to Distribution Pipeline 

Systems 

The basic premise of the integrity 

management programs for gas 

transmission and hazardous liquid 

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4The public meetings concerning integrity 

management requirements were held on December 

16, 2004 and September 21, 2005. A third meeting, 

on June 17, 2005, focused exclusively on 

appropriate requirements for excess flow valves. 

Summaries of all meetings are in the docket. 

5American Gas Foundation, ‘‘Safety Performance 

and Integrity of the Natural Gas Distribution 

Infrastructure,’’ January 2005, available at http:// 

www.aga.org/Template.cfm/Section=NonAGA_Studies_Forecasts_Stats&template. 

pipelines—that safety is improved by 

identifying risks and taking actions to 

address them—is applicable to 

distribution pipeline systems. However, 

because of the differences between 

distribution pipeline systems and 

pipeline systems covered by current IM 

regulations, the physical inspections 

(e.g. In-Line Inspection tools and Direct 

Assessment methods) of pipeline 

segments required by the current IM 

regulations cannot be required on 

distribution pipelines. Because the same 

IM regulations will not work, a different 

type of integrity management approach 

is necessary. 

Distribution Systems Are Located in 

Highly Populated Areas 

The first element of existing IM 

program requirements for transmission 

pipelines is to identify so-called ‘‘high 

consequence areas’’—those segments of 

the pipeline where an incident/break 

could produce serious harm to people or 

the environment. This is important for 

hazardous liquid and gas transmission 

pipelines because both traverse large 

distances, including areas that are 

sparsely populated or where risk of 

serious environmental damage would be 

small. Identifying high consequence 

areas improves the effectiveness of 

integrity management requirements by 

focusing inspection and assessment 

efforts on the pipe where significant 

consequences could occur. 

As described above, gas distribution 

pipeline systems are different. Unlike 

transmission pipelines, they do not 

traverse long distances and generally do 

not include significant areas of limited 

population. They operate almost 

entirely in populated areas, because 

their purpose is to provide gas service 

to the residences and businesses of 

those populations. Thus, by contrast to 

a transmission pipeline, identifying 

areas where the gas distribution 

pipeline is near concentrations of 

people would not tend to identify a 

limited portion of the pipeline on which 

integrity management attention should 

be focused. Some other means of 

prioritizing operator attention, based on 

risk, is needed for distribution 

pipelines. 

Challenges of Assessment or Testing 

As described above, distribution 

pipeline systems consist of a complex 

network of mains and services. They 

include considerable lengths of pipeline 

of very small diameter and many nonmetallic materials. They also include 

extensive branching, with a typical city 

main being connected to a new service 

roughly every one hundred feet. These 

differences make it impossible to use 

many of the techniques required by the 

existing IMP regulations to assess the 

physical condition of the pipeline. One 

technique (in-line inspection) involves 

passing through the inside of a pipeline 

inspection tools that use magnetic 

detection techniques to identify areas 

where the wall of a steel pipe has been 

thinned by corrosion or damage. 

Another (direct assessment) involves 

using indirect inspection tools to 

identify areas where the electrical 

current imposed on steel pipes to 

prevent corrosion is interrupted or is 

experiencing interference. Distribution 

pipelines are too small and have too 

many connections to allow in-line 

inspection tools to pass through the 

lines, and approximately half of the 

distribution pipeline system is nonmetallic (e.g., plastic), meaning that 

neither the internal tools nor the 

indirect inspections used for direct 

assessment can be used. Pressure testing 

(isolating a pipe and filling it with water 

or air at high pressure to see if it leaks) 

can be used, but would require that 

service be cut off to all customers served 

by the portion of the system being 

tested. A continuing program of such 

testing would essentially constitute the 

natural gas equivalent of ‘‘rolling 

blackouts’’ and would be unacceptable 

to the American public. Distribution 

pipelines can be inspected by digging to 

expose the pipeline, and operators are 

required to do such inspections when 

pipe must be excavated for other 

reasons. Digging up all distribution 

pipelines on a periodic basis, however, 

is clearly impractical. 

For these reasons, the inspection 

requirements of current IMP regulations 

cannot be used for distribution 

pipelines. 

Some other approach is needed. As 

described below, PHMSA worked with 

stakeholder groups and held two public 

meetings to help determine how best to 

apply IMP principles in the gas 

distribution pipeline environment.4

These public meetings are discussed 

further below. 

II. American Gas Foundation Study 

The gas distribution industry 

recognized the need to consider its 

safety record and to determine if 

additional actions are needed. In late 

2003, the American Gas Foundation 

(AGF) launched a study of the safety 

performance and integrity of gas 

distribution pipeline systems. Currently, 

operators must report an incident to 

PHMSA if it meets the reporting criteria 

in 49 CFR Part 191. The AGF study 

examined the record of incidents 

reported to PHMSA on gas distribution 

pipeline systems from 1990 through 

2002 (the latest year for which data were 

complete at the time the study began) 

and compared that record to incidents 

reported for transmission pipelines over 

the same period. 

The AGF study analyzed trends in 

reported incidents and focused 

specifically on incidents involving 

deaths or injuries requiring 

hospitalization (called ‘‘serious 

incidents’’ in the study). A joint team, 

the Distribution Infrastructure 

Government-Industry Team (DIGIT), 

was established to oversee the AGF 

study. This team consisted of 

representatives of the AGF, the 

American Public Gas Association, and 

State pipeline safety regulators. PHMSA 

took part in DIGIT as an observer. 

The AGF published its findings in 

January 2005.5 The AGF study found a 

downward trend in serious incidents 

over the 13-year period analyzed at a 95 

percent statistical confidence level. (No 

statistically significant trend was found 

when considering all reported 

incidents.) The number of serious 

incidents per 100,000 miles of 

distribution pipeline was essentially the 

same as that for gas transmission 

pipelines over the analyzed period. 

There are many more miles of 

distribution pipelines, however. 

Historically, distribution pipeline 

incidents result in more deaths and 

injuries than incidents on gas 

transmission or hazardous liquid 

pipelines, largely because distribution 

lines are located in populated areas and 

constitute a much larger share of the 

mileage of working pipelines. 

AGF found the primary cause of 

serious incidents was outside force 

damage, principally third-party 

excavation. Outside force damage 

represented 47 percent of serious 

incidents over the analyzed period. 

Corrosion caused 6.5 percent of serious 

incidents, and all other causes 

contributed less than 10 percent each. 

AGF also examined practices gas 

distribution operators use to address 

threats to their systems, both those 

required by regulation and those 

performed voluntarily. The study found 

no obvious gaps and that industry 

practices exist to address known threats. 

Further, the study concluded (as for 

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6Audit report SC–2004–064, issued June 14, 

2004. 

7 Id. 

8 49 CFR 192.383. 

hazardous liquid pipelines and gas 

transmission pipelines) serious 

incidents continue to occur (albeit 

rarely) despite compliance with existing 

regulations. 

III Recommendations or Mandates of 

Oversight Bodies 

A. DOT Inspector General 

In a report published June 14, 2004,6

the DOT’s Inspector General (IG) found 

that recent accident trends for gas 

distribution pipelines are not favorable. 

The IG noted that nearly all of the 

natural gas distribution pipelines are 

located in highly-populated areas, such 

as business districts and residential 

communities, where a rupture could 

have the most significant consequences. 

As a result, the audit pointed out for the 

10-year period from 1994 through 2003, 

accidents on natural gas distribution 

pipelines have resulted in more 

fatalities and injuries than accidents on 

hazardous liquid and natural gas 

transmission lines combined. 

The IG also recognized that applying 

risk management principles to 

distribution pipelines could help 

reverse these trends. In testimony before 

Congress in July 2004,7 the IG 

recommended that PHMSA should 

define an approach for requiring 

operators of distribution pipeline 

systems to implement some form of 

integrity management or enhanced 

safety program with elements similar to 

those required in hazardous liquid and 

gas transmission pipeline integrity 

management programs. 

B. National Transportation Safety Board 

The National Transportation Safety 

Board (NTSB) investigates serious 

pipeline accidents, including those that 

occur on gas distribution pipeline 

systems. Over the years, the NTSB has 

made several recommendations to 

improve safety regulation of gas 

distribution pipelines. In particular, the 

NTSB has recommended the use of 

excess flow valves (EFVs) in all new 

construction and replaced service 

pipelines. 

EFVs have received significant 

attention as a mitigation option for gas 

distribution systems. Current Federal 

regulations require that operators notify 

service line customers for new and 

replaced service lines of the availability 

and potential safety benefits of 

installing EFVs.8 In lieu of this 

notification, operators may elect to 

install the valves voluntarily when 

certain conditions apply. The valves are 

generally applicable for new 

installations or complete service piping 

replacement for single-family residential 

homes, where the operating pressure is 

greater than 10 pounds per square inch 

(psi). Operators must install the valve if 

the customer agrees to pay for the cost 

of such installation. Discussions with 

operators indicate that approximately 

30% of distribution system operators are 

installing the valves as a routine part of 

new and replaced service installations 

in situations in which they apply. Many 

of these are larger distribution operators, 

so the percentage of new and replaced 

service line installations voluntarily 

including EFVs is higher. 

PHMSA conducted additional studies 

on the effectiveness of the valves and on 

the experience that has been gained as 

a result of their use. NAPSR assisted in 

these studies. PHMSA concluded that 

EFVs, if specified and installed 

correctly, operate reliably to cut off the 

supply of gas in the event of major 

damage to the downstream service line 

(e.g., excavation damage). While 

performance problems had occurred 

with early installation of EFVs, the data 

also show that the valves seldom now 

suffer false activations, cutting off the 

supply of gas when no damage has 

occurred. 

EFVs installed in new construction or 

replaced service lines would mitigate an 

incident occurring on service lines in 

which the line was severed. The valves 

are designed to operate in the event of 

line ruptures that result in major flow of 

gas. At the same time, they are an 

inexpensive option for mitigating such 

incidents. The valves themselves cost 

less than $20 and the cost to install 

them, when a service line is being 

installed or replaced is nominal. They 

will not operate in the event of small 

leaks. They will not operate in the event 

of leaks or problems within a customer’s 

residence or business, downstream of 

their pressure regulator, including 

situations in which a fire in a residence 

results in a breach of a gas appliance 

line in the residence. 

PHMSA asked Allegro Energy 

Consulting to review incident report 

records to estimate how many incidents 

might have been mitigated by the 

presence of an excess flow valve had 

one been installed at construction or 

during repair. Allegro reviewed 634 

incident reports submitted between 

1999 and 2003. They screened out those 

that did not involve service lines, that 

were obviously slow leaks, or which 

otherwise did not appear to meet the 

criteria as incidents for which an excess 

flow valve would be beneficial. As a 

result, Allegro identified 101 incidents 

in which the presence of an EFV might 

have mitigated consequences over this 

five-year period. To be clear, this is an 

estimate. The incident reports do not 

include some information (e.g., gas flow 

rate) that is necessary to ascertain 

definitively whether an excess flow 

valve would have been effective. They 

do not include information on whether 

the 25% of fatalities or injuries in which 

automobiles struck gas meter set 

assemblies at the side of homes could 

have been prevented by an EFV shutting 

off gas flow. 

PHMSA also conducted a public 

meeting concerning EFVs, which is 

described in Section VI below. 

C. Congressional Mandate 

Subsequent to the stakeholder groups’

recommendations discussed below and 

the public meeting, Congress passed the 

Pipeline Inspection, Protection, 

Enforcement, and Safety Act of 2006 

(PIPES Act), which the President signed 

into law in December 2006. The Act 

included a mandate that PHMSA 

require gas distribution operators to 

implement integrity management 

programs and to install EFVs in all new 

or replaced residential gas service lines 

where operating conditions are suitable 

for available valves, beginning June 1, 

2008. This proposed rule includes 

requirements addressing this mandate, 

which will no longer require the 

customer notification requirements of 

§ 192.383. Thus, we are proposing to 

repeal this requirement. 

IV. Stakeholder Groups 

A. Stakeholder Groups’ Involvement 

In 2004, as described above, the IG 

recommended that PHMSA establish IM 

requirements for distribution pipelines, 

including elements similar to those in 

the IM regulations for hazardous liquid 

and gas transmission pipelines (except 

for those related to physical inspection 

(i.e., assessment, of the pipeline). The IG 

highlighted this recommendation in 

testimony before Congress in 2004, and 

a report of the fiscal year (FY) 2005 

Conference Committee on 

Appropriations required DOT to report 

its plans to establish such regulations. 

PHMSA filed its report in June 2005. A 

copy of the report is in the docket. 

PHMSA’s report to Congress 

described the work of four stakeholder 

groups to investigate opportunities to 

enhance the safety of distribution 

pipelines. The four multi-stakeholder 

groups (viz. Excavation Damage Group, 

Data Group, Risk Control Practices 

Group and Strategic Operations Group), 

representing State regulators, the public, 

and the gas distribution industry, 

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9A ticket is the information the underground 

facility operator receives from the one-call 

notification center. 

collected and analyzed available 

information and issued a report of their 

investigations in December 2005. A 

copy of the report is in the docket. The 

groups agreed IM requirements for 

transmission pipelines could not be 

applied directly to distribution systems 

because gas distribution pipeline 

systems differ significantly from 

transmission pipelines in their design. 

The groups also found that diversity 

among gas distribution pipeline 

operators and systems was so great that 

prescriptive requirements suitable for 

all circumstances could not be 

established. Instead, the groups found it 

would be more appropriate to require all 

distribution pipeline operators, 

regardless of size, to implement an IM 

program, including seven key elements. 

These seven elements are described 

below under ‘‘Stakeholder Group 

Findings.’’

The groups concluded that 

distribution IM requirements should 

apply to all distribution pipeline 

systems, rather than just to portions of 

systems in high-consequence areas. 

Distribution pipeline systems are 

located in populated areas, where 

incidents are likely to produce serious 

consequences. Because distribution 

pipelines operate at very low pressures, 

failures typically appear as leaks. 

Experience shows gas released through 

leaks can migrate underground and 

collect in nearby buildings or other 

locations. These leaks can result in fires 

and explosions in locations not directly 

on the pipeline. Thus, the method used 

to identify high consequence areas along 

transmission pipelines—predicated on 

the likelihood that a fire or explosion 

would occur at the rupture location—

would be irrelevant to gas distribution 

systems. 

The stakeholder groups generally 

concluded IM requirements for 

distribution pipelines should be 

established by a regulation that sets 

high-level performance objectives with 

implementation guidelines. This 

approach would allow States flexibility 

in implementing IM programs suited to 

their particular circumstances; operators 

flexibility in better identifying the 

sources of risk to their pipelines; and 

more focused actions aimed at 

addressing those risks. 

B. Stakeholder Groups’ Findings 

The stakeholder groups made the 

following findings and conclusions 

about the current state of gas 

distribution pipeline safety and 

integrity: 

1. Distribution pipeline safety and 

excavation damage prevention are 

intrinsically linked. Excavation damage 

poses, by far, the most significant threat 

to the safety and integrity of gas 

distribution pipeline systems. 

Therefore, excavation damage 

prevention presents the greatest 

opportunity for gas distribution system 

safety improvements. Any effort to 

improve distribution pipeline safety is 

flawed if it does not seriously address 

excavation damage prevention. 

2. The dominant cause of reportable 

distribution pipeline incidents is 

‘‘excavation damage,’’ while ‘‘other 

outside force’’ and ‘‘natural force’’ are 

the second and third leading causes. 

3. Corrosion is the principal cause of 

distribution pipeline leaks removed for 

both mains and service lines, but it 

causes relatively few incidents. 

4. ‘‘Excavation damage’’ is nearly as 

significant as ‘‘corrosion damage’’ in 

causing service line leaks. 

5. Excavation damage and material/ 

weld failures, respectively, are the 

second and third leading causes of leaks 

for both mains and service lines. 

6. Corrosion causes approximately 

four percent of incidents, indicating 

operators are managing corrosion to 

prevent it from becoming one of the 

major contributors to reportable 

incidents. 

7. The rate of reportable distribution 

incidents resulting in deaths and 

injuries has decreased from 1990 to 

2002. (Note that the Inspector General’s 

analysis and AGF study were conducted 

for different periods.) 

8. No statistically significant trend 

could be determined for total reportable 

distribution incidents for the same 

period. 

9. There is a downward trend for 

reportable incidents resulting in deaths 

or injuries caused by damage from 

outside force. 

10. Although not statistically 

analyzed, the data suggest a slight 

downward trend in corrosion-caused 

leaks, and a decreasing trend in leaks 

caused by third-party damage. 

C. Stakeholder Conclusions 

Based on their findings, the groups 

concluded: 

1. The most useful option for 

imposing distribution IM requirements 

would be a high-level, flexible Federal 

regulation, with implementation 

guidance. 

2. Seven elements could describe the 

basic structure of a high-level, flexible 

Federal regulation addressing 

distribution IM. Each operator would 

have to do the following regarding its 

pipeline system: 

• Develop a written program 

describing management of the integrity 

of the distribution system; 

• Have an understanding of the 

system, including the conditions and 

factors important to assessing risks; 

• Identify threats applicable to the 

system, including potential future 

threats; 

• Assess risks and characterize the 

relative significance of applicable 

threats to the system; 

• Identify and put in place 

appropriate risk-control practices (or 

modify current risk-control practices) to 

prevent and mitigate risks from 

applicable threats consistent with the 

significance of these threats; 

• Develop and monitor performance 

measures to evaluate effectiveness of 

programs, periodically evaluate program 

effectiveness, and adjust programs as 

needed to assure effectiveness; and 

• Periodically report a select set of 

performance measures to jurisdictional 

regulatory authorities. 

3. Because a distribution IM program 

would cover the entire distribution 

system, there is no need to identify 

high-consequence areas. 

4. A distribution IM program should 

consider threats identified in the 

PHMSA Annual Distribution Report, 

PHMSA Form 7100.1–1, as ‘‘Cause of 

Leaks’’ in Part C: 

• Corrosion; 

• Natural Forces; 

• Excavation Damage; 

• Other Outside Force; 

• Material or Welds (Construction); 

• Equipment; 

• Operations; and 

• Other 

5. Distribution IM requirements 

should not exclude any class or group 

of local distribution companies. 

6. Operators may need guidance 

materials to comply with a high-level, 

risk-based, flexible federal rule. Small 

operators may need more precise 

compliance guidance. 

7. Implementation of elements of 

distribution IM regulations should be 

based on information reasonably 

accessible to an operator and on 

information an operator can collect on 

a going-forward basis. Regulations 

should not require extensive research. 

8. The most useful performance 

measures at the national level could be 

incidents (per mile or per service), 

number of excavation damages per 

‘‘ticket,’’ 9 the status of implementing 

elements of the rule, the amount of pipe 

that is not state-of-the-art, and a 

redefined measure or measures related 

to leaks. 

9. Operator-specific performance 

measures are unique and must match 

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10NTSB, ‘‘Natural Gas Explosion and Fire at 

South Riding Virginia, July 7, 1998,’’ Pipeline 

Accident Report PAR–01/01, June 12, 2001. 

11 Ibid. 

12NAPSR is an organization consisting of the 

state pipeline safety program manager from each 

state that exercises jurisdiction over pipeline safety. 

the specific risk-control practices of its 

distribution IM program. 

10. The operator should periodically 

evaluate the effectiveness of its 

distribution IM program. Programs 

should specify the period for evaluating 

program effectiveness, which should be 

as frequently as needed to assure 

distribution system integrity. 

11. Operators should review and 

implement Common Ground Alliance 

(CGA) Best Practices, and other industry 

practices as appropriate, to reduce 

damages to their facilities. Similarly, 

other affected stakeholders should 

review and implement applicable CGA 

Best Practices. 

12. A joint stakeholder group formed 

to conduct an annual review of safety 

performance metrics data, to resolve 

issues, and to produce a national 

performance metrics report would be of 

considerable value. 

D. Findings Relevant to Leak 

Management 

As described above, the stakeholder 

groups found that although corrosion is 

the dominant cause of leaks repaired on 

gas distribution pipeline systems, 

corrosion accounts for only four percent 

of gas distribution incidents. This 

reflects the importance and 

effectiveness of leak management 

practices operators currently use. The 

stakeholder groups agreed leak 

management is an important risk control 

practice and should be a part of a gas 

distribution IM program, along with 

excavation damage prevention. 

According to the stakeholder groups, 

the essential elements of an effective 

leak management program are as 

follows: 

• Locate the leak; 

• Evaluate its severity; 

• Act appropriately to mitigate the 

leak; 

• Keep records; and 

• Self-assess to determine if 

additional actions are necessary to keep 

the system safe. 

These elements are collectively referred 

to by the acronym LEAKS, representing 

the first letter of each element. 

E. Stakeholder Considerations 

Regarding Excess Flow Valves 

The stakeholder groups devoted 

considerable attention to excess flow 

valves (EFVs) in the context of potential 

IM program requirements. As described 

above, an EFV is designed to stop the 

flow of gas in a service line 

experiencing major leakage, generally 

caused by excavation damage. The 

device prevents consequences 

associated with a significant escape of 

gas and its ignition. An EFV in a service 

line provides no protection for breaks 

downstream of the meter (in homes). 

Since pressure is reduced at the meter 

and the flow through, even a completely 

severed line in the home poses much 

less risk than if the same break were to 

occur on the higher-pressure service 

line upstream of the meter. 

The stakeholder groups considered 

the use of EFVs for IM and reached the 

following conclusions: 

1. Information drawn from surveys of 

State practices and operational 

experience for currently installed EFVs 

indicated: 

• Over 6.3 million EFVs have been 

installed in the United States (i.e., 

protecting approximately 10% of all 

services). 

• If correctly specified and installed, 

EFVs work as designed. 

• EFVs will not work in all 

applications—for example, EFVs will 

not work in up to 60 percent of new 

services in Connecticut, a State favoring 

their use, because the service lines 

operate at pressures below that required 

for EFVs to function. 

2. Regulations should not require 

installation of EFVs on all new and 

replaced service lines. EFVs are one 

risk-control practice operators should 

consider along with others. 

3. Operators, as part of their 

distribution IM program, should 

consider the mitigative value of 

installing EFVs. 

In their findings, the stakeholder 

groups considered the NTSB’s 

recommendation that DOT require 

installation of EFVs on all new and 

replaced gas service lines where 

operating pressure exceeds 10 psig.10

This recommendation resulted from the 

NTSB’s investigation of a 1998 accident 

in South Riding, Virginia, which 

destroyed a new home and killed one of 

its occupants.11 The NTSB concluded 

the accident was caused by gas escaping 

from a hole in the gas service line and 

the flow through that hole was of 

sufficient magnitude that an EFV would 

have prevented the accident. 

Comments From Fire Service 

Organizations 

The stakeholders also considered 

comments from representatives of the 

fire service organizations. The 

International Association of Fire Chiefs 

and the International Association of Fire 

Fighters wrote to the Secretary of 

Transportation in early 2004 urging 

DOT to require installation of EFVs. The 

organizations commented that fire 

fighters are often first to respond to 

incidents involving fires fueled by 

escaping gas and their lives were at risk 

in doing so. The same organizations, 

along with the National Volunteer Fire 

Council and the Congressional Fire 

Services Institute, wrote to PHMSA 

again in 2005 after reviewing draft 

reports of the Risk Control Practices 

stakeholder group. The fire service 

organizations reiterated their 

recommendation about mandatory EFV 

installation and disagreed with the 

group’s conclusion that EFVs should be 

treated under distribution IM 

requirements as one of the available 

mitigation options. 

(Note that the conclusions of the 

stakeholder groups are reported here for 

completeness, but that many have been 

rendered moot by the statutory mandate, 

enacted after the stakeholder group 

deliberations, that installation of EFVs 

be made mandatory) 

Surveys 

In conjunction with stakeholder group 

findings, PHMSA considered the results 

of several surveys evaluating the 

prevalence and efficacy of EFVs in gas 

distribution systems. One survey, 

conducted by the National Regulatory 

Research Institute (NRRI), a universitybased research arm of the National 

Association of Regulatory Utility 

Commissioners (NARUC), surveyed 

State regulatory commissioners, partly 

in response to PHMSA’s interest in the 

subject. A second survey conducted by 

the National Association of Pipeline 

Safety Representatives (NAPSR) 12

obtained results from pipeline safety 

program managers in all States (and the 

District of Columbia) with regulatory 

jurisdiction over distribution pipeline 

safety. A third survey, sponsored by 

PHMSA and conducted by Oak Ridge 

National Laboratory, examined in more 

detail the experience of nine gas 

distribution operators, some of whom 

install EFVs voluntarily and others who 

install in conformance with the 

requirements of 49 CFR 192.383. Results 

of all three surveys are available in the 

docket for this rulemaking. 

The surveys indicate EFVs, if 

correctly sized and installed, operate 

reliably. Instances of false closure, 

where gas flow stops even though the 

service line is undamaged, rarely occur. 

Likewise, the valves function reliably 

when service lines are damaged. In fact, 

one potential problem with EFVs —the 

increased risk that excavation-related 

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13Underground utilities are usually installed by 

digging a trench, laying the pipe or cable in the 

trench and refilling it. In such installations, damage 

to other utilities would be obvious. Directional 

boring is a technique used when trenching is 

impractical, often when utilities must be installed 

below paved surfaces. When directional boring is 

used, a service line could be damaged or severed. 

If an installed EFV operates properly to shut off the 

flow of gas, the installer may not even be aware that 

a gas service line has been damaged. 

damage will go unreported—is directly 

related to their effectiveness in stopping 

the flow of gas from a severed gas line. 

In some cases, particularly where 

directional boring 13 is used, excavators 

may not even 0be aware they have 

damaged a gas service line. When an 

excavator damages a service line not 

protected by an EFV, gas is released and 

the excavator must stop work and notify 

the gas distributor to protect the safety 

of its own personnel and the house at 

which they are working. If an EFV is 

installed, the EFV functions to stop the 

flow of gas, and an irresponsible 

excavator can finish its work, re-fill the 

hole, and leave the site. Only later, 

when the residents discover they have 

no gas service, is the damage reported. 

The gas distribution operator must then 

re-excavate to locate and repair the 

damage, increasing the expense of the 

repair. Although anecdotal evidence 

shows excavators do not always notify 

operators of damage to service lines, 

PHMSA does not have the data to 

determine if this is a prevalent problem. 

V. Public Meetings 

A. Public Meetings Concerning 

Distribution Integrity Management 

PHMSA conducted two public 

meetings to collect and evaluate public 

comments on the potential for adding 

IMP requirements for distribution 

pipelines. During the first meeting, held 

December 16, 2004, presentations were 

made concerning the then-draft AGF 

study discussed above and the DOT IG’s 

recommendation. Comments made at 

this meeting resulted in the stakeholder 

group investigations, which are 

discussed in section VI. 

The second public meeting, held on 

September 21, 2005, included 

presentations describing the stakeholder 

group investigations, which were then 

in progress. Participants included 

representatives of industry, State 

regulators, PHMSA, and the public, 

including persons involved in the 

stakeholder investigations. Key points 

made by meeting participants included 

the following: 

• There must be a balance among 

improved safety, reliability, and costs. 

For municipal operators, cost trade-off 

involves potential effects on other 

community services, including public 

safety. 

• The primary cause of incidents on 

distribution systems is outside force 

damage, and any action must address 

this threat. Operators have limited 

ability to prevent excavation damage, 

and excavators are not typically under 

the jurisdiction of pipeline safety 

authorities. Comprehensive damage 

prevention programs can reduce 

incidence of excavation damage. 

• Leak management is an important 

element in assuring the integrity of gas 

distribution pipelines. 

• The majority of companies affected 

by any new distribution IM 

requirements are small companies, and 

the needs of those operators differ from 

larger companies. Smaller companies 

will likely require more detailed 

guidance for implementing new rules. 

Summaries of both public meetings 

are in the docket. 

B. EFV Public Meeting 

On June 17, 2005, PHMSA conducted 

a public meeting to discuss EFV 

performance, notification, and 

installation issues. The meeting 

included panel discussions involving 

members of industry, State 

governments, fire service organizations, 

the National Association of Fire 

Protection, advocacy groups, the NTSB, 

and researchers who analyzed EFV 

performance. 

Industry participants included 

representatives of companies 

voluntarily installing EFVs and those 

installing only when a customer 

requested. These company 

representatives said they analyzed the 

costs and benefits of installing EFVs 

under local conditions in deciding 

whether to install EFVs. Factors in these 

analyses include the size and growth 

rate of company service areas, costs of 

maintaining records related to 

notifications, experience with load 

growth after initial installation (which 

can result in a need to replace EFVs), 

and the relative effectiveness of 

alternative actions to reduce the threat 

of excavation damage. Operators also 

noted they have experienced instances 

in which excavators damaged a line 

equipped with an EFV, but the damage 

was not reported to the operator, 

increasing operator costs to repair the 

damage. 

PHMSA and Allegro Energy described 

PHMSA-sponsored research on EFV 

performance (discussed above). The 

research examined incidents reported 

on gas distribution systems over a fiveyear period (634 events)—the Allegro 

Energy analysis described above. The 

PHMSA study examined these 

narratives and concluded EFVs could 

have been a factor in mitigating 101 

(approximately 16 percent) of the 

analyzed incidents. 

The NTSB reported that serious 

accidents on gas distribution systems 

prompted its recommendation that 

PHMSA require EFV installation. 

Recognizing that States conduct most 

regulatory oversight of distribution 

operators, the NTSB contacted all State 

governors in 1996, recommending they 

establish requirements for mandatory 

installation,. The responses to those 

recommendations—indicating States 

look to PHMSA for safety standards—

reinforced the NTSB’s support for a 

Federal requirement. 

Representatives of State pipeline 

safety authorities, utility 

commissioners, and regulatory program 

managers described the factors 

considered by States in evaluating EFVs. 

They said local conditions could affect 

decisions on whether to use the valves. 

Initial installation costs are small, but 

life-cycle costs must be considered. 

They reported that EFVs provide 

protection from a limited scope of 

incidents involving significant damage 

to, or severance of, a service line. Many 

operators reported their belief that their 

resources are better spent attempting to 

reduce the frequency of those events 

rather than on installing EFVs. While all 

agree damage reduction activities can 

improve safety for existing gas services, 

they believe retrofit installation of EFVs, 

where the service line is not being 

replaced for other reasons, is 

impractical. 

Public safety advocates expressed 

significant concern with the manner in 

which operators are implementing the 

notification requirements in 49 CFR 

§ 192.383. Often the ‘‘customer’’ notified 

about the availability of EFVs for newly 

installed services is a builder/developer 

rather than the resident of a home. 

Experience indicates few builders/ 

developers elect to have EFVs installed. 

When homes are then occupied shortly 

after the gas service is installed, the 

customer neither enjoys the protection 

of an EFV nor has the opportunity to 

decide to pay for the added protection. 

Comments From Fire Service 

Representatives 

Fire fighters participated in the 

stakeholder groups and public meetings. 

Because the consequences of accidents 

on gas distribution pipelines generally 

result from fires fed by escaping gas, fire 

fighters have a significant interest in 

reducing the frequency and 

consequences of such events. 

As described above, the International 

Association of Fire Chiefs, the 

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36024 Federal Register / Vol. 73, No. 123 / Wednesday, June 25, 2008 / Proposed Rules 

International Association of Fire 

Fighters, the National Volunteer Fire 

Council, and the Congressional Fire 

Services Institute support a requirement 

to install EFVs in all new and replaced 

service lines where installation is 

suitable. Additionally, these 

organizations support IM programs for 

gas distribution operators to identify 

and evaluate specific risks associated 

with their systems and to implement 

measures to minimize those risks. The 

organizations agreed most operators will 

need guidance to implement these 

requirements and small operators are 

likely to need guidance that is more 

precise. These organizations also believe 

it is vital for operators to implement 

strategies to reduce the frequency of 

outside force damage. The comments of 

these organizations are in the report of 

the stakeholder group investigations and 

are in the docket. 

Representatives of the National 

Association of State Fire Marshals 

(NASFM) and the National Fire 

Protection Association (NFPA) 

participated in stakeholder groups. State 

Fire Marshals are responsible for 

overseeing compliance with State fire 

codes and related building standards, 

training fire fighters, and other duties 

based on State agency assignments. 

NFPA is a professional association 

responsible for developing American 

National Standards Institute approved 

consensus standards related to fire 

safety. 

NASFM also supports mandatory 

installation of EFVs. In comments made 

at the June 2005 public meeting on EFVs 

and the September 2005 public meeting 

on distribution IM, NASFM also 

supported a comprehensive approach to 

IM. This approach would address all 

threats, prioritize them for action, and 

deal with them based on importance. 

NFPA also supports IM requirements 

for gas distribution pipelines and agrees 

new requirements for distribution 

systems will primarily affect smaller 

operators who will need detailed 

guidance to implement them. NFPA 

acknowledges EFVs will reliably stop 

gas flow if the flow exceeds their trip 

point, but cautions that the valves are 

not a panacea because damage to a 

service line may not always result in 

sufficient flow to trip an EFV. 

A complete summary of this meeting 

is available in the docket. 

VI. Guidance for IM 

As described above, the stakeholder 

groups concluded operators would need 

guidance to implement a regulation 

requiring operators to meet high-level 

performance objectives to improve IM. 

The diversity among distribution 

systems and the size/capabilities of 

distribution operators make it 

impractical to require specific, detailed 

actions in the regulation. In particular, 

the stakeholder groups described above 

reported to PHMSA that operators need 

guidance to describe the following: 

1. Information they should gather 

through routine activities to improve 

their understanding of the distribution 

system infrastructure. 

2. How best to assemble detailed 

information on pipe characteristics 

(including material, manufacturer, 

batch, etc.) to strengthen their 

understanding of the system and to 

support current and future riskmanagement activities. 

3. Threat evaluation processes and 

data needed to support this evaluation. 

4. Options for evaluating the relative 

importance of threats. 

5. How to perform risk analysis, 

encompassing situations from small, 

simple distribution systems to large and 

complicated ones, and how to use the 

results of these analyses. 

6. Decision processes and criteria for 

choosing among prevention, detection, 

and mitigation measures. 

7. Options for measuring safety 

program effectiveness and determining 

the situations under which different 

measures would be meaningful. 

8. How to evaluate the overall 

effectiveness of the program such as 

how to determine if the program is 

being implemented as described and 

how to determine if the program is 

producing improvements. 

9. How to structure a comprehensive 

leak management program, which is 

fundamental to successful management 

of distribution risk. At a minimum, 

operators need guidance to implement 

the LEAKS program or the following: 

—Determine how local conditions and 

system knowledge should affect the 

frequency and type of leak surveys. 

—Identify methods/criteria for 

evaluating the severity of leaks and 

need for action. 

—Describe records an operator should 

maintain to permit trending and 

identification of underlying problems. 

—Identify performance metrics and the 

types of analyses in which the 

operator should consider them. 

On March 2, 2006, PHMSA asked the 

Gas Piping Technology Committee 

(GPTC), a standards-developing body, to 

prepare guidance. GPTC is accredited by 

the American National Standards 

Institute (ANSI), the governing body for 

consensus standards development in the 

U.S. GPTC has historically prepared 

guidance to assist operators in 

implementing various parts of natural 

gas pipeline safety regulations in 49 

CFR Part 192. GPTC agreed and formed 

a Distribution Integrity Guidance Task 

Force to develop guidance. The GPTC 

guidance will provide suggestions for 

operators concerning options they could 

use to implement the high-level 

requirements in a final rule. The GPTC 

will describe the scope and content of 

the guidance at a public meeting during 

the comment period. 

The GPTC guidance is designed to 

assist operators in developing their 

distribution integrity management 

programs. PHMSA expects the guidance 

will provide options that operators can 

use to implement the DIMP 

requirements and that inspectors, 

primarily from State pipeline safety 

agencies, also will use the guidance as 

examples of actions an operator could 

take to comply with the rule. It will be 

up to each operator to develop its plan 

implementing the DIMP requirements. 

The GPTC guidance is only intended to 

assist operators; operators may use other 

approaches. Whatever approach and 

guidance an operator uses to develop its 

plan, it will be up to the operator to 

demonstrate how its approach satisfies 

the DIMP requirements. When 

inspectors identify deficiencies in 

operator plans and procedures intended 

to satisfy the requirements, they will use 

existing enforcement tools, based on 

non-compliance with the rule (not with 

the guidance) to cause operators to 

comply. PHMSA is not proposing to 

incorporate by reference the GPTC 

guidance. 

PHMSA understands the GPTC 

guidance will be published for public 

comment, as part of the ANSI approval 

process, after this NPRM is published. 

PHMSA also is supporting work by 

the American Public Gas Association 

(APGA) Security and Integrity 

Foundation (SIF) to develop more 

specific guidance for use by the smallest 

operators. These are usually 

municipalities that have limited 

resources to develop IM programs. SIF 

is a non-profit 501(c)(3) corporation, 

which was established by the APGA in 

2004. The SIF is dedicated to promoting 

the security and operational integrity 

and safety of small natural gas 

distribution and utilization facilities. 

The SIF will focus its resources on 

enhancing the abilities of gas utility 

operators to prevent, mitigate and repair 

damage to the nation’s small gas 

distribution infrastructure. In this work, 

SIF is using the GPTC guidance to 

develop a computer program that will 

assist small operators in developing 

their IM programs. 

PHMSA and NAPSR have formed a 

joint workgroup to develop a framework 

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14Section 192.1(b)(6) states the requirements of 

Part 192 do not apply to operators of ‘‘any pipeline 

system that transports only petroleum gas or 

petroleum gas/air mixtures to—(i) Fewer than 10 

customers, if no portion of the system is located in 

a public place.’’

for oversight of the Federal 

requirements for the distribution 

integrity management program. This 

joint workgroup is charged with 

developing an oversight program that 

provides consistency in the States’

oversight of operator plans. The 

guidance developed by GPTC will be 

key to this process. States have the 

responsibility for designing and 

implementing their oversight programs, 

but PHMSA needs certain information 

from these programs to evaluate the 

effectiveness of the new Federal 

requirements, report results to Congress 

and organizations that oversee us, and 

determine if future changes are needed. 

PHMSA’s goal in this workgroup is to 

provide regular reporting on progress 

and results of inspections of distribution 

operators’ compliance with the final 

DIMP rule. 

VII. Applicability to Small and Simple 

Distribution Systems; Request for 

Comments 

A. Master Meter and Liquefied 

Petroleum Gas (LPG) Operators 

We believe IM regulations for master 

meter and LPG operators should be 

limited because these systems are 

simple and seem to pose relatively little 

risk. 

By contrast to other local distribution 

systems, master meter system operators 

receive gas at a single meter (the master 

meter) and operate small pipeline 

systems to deliver the gas from the 

meter to a small number of users. A 

typical example of a master meter 

operator is a trailer park where the 

trailer park owner/operator receives gas 

from a local distribution company and 

distributes it, via underground piping, 

to individual trailer pads. Master meter 

pipeline systems tend to cover limited 

geographical areas. They are simple 

systems, often including only one type 

of pipe, operating at a single pressure, 

and having no equipment other than 

pipe, meters, service pressure 

regulators, and valves. 

Master meter operators are subject to 

the requirements of Parts 191 and 192, 

but some requirements are modified to 

better suit these simpler systems. For 

example, master meter operators must 

have damage prevention plans under 

§ 192.614, but their plans do not have to 

be written. Similarly, these operators 

must provide notification of incidents 

by telephone (§ 191.5) but do not have 

to submit written incident reports 

(§ 191.9) or annual reports (§ 191.11). 

These modifications recognize these 

systems are generally simple and 

represent less risk. 

LPG systems are small systems, 

mostly in rural areas, that use liquefied 

petroleum gas to serve a number of 

customers, usually in areas not served 

by natural gas transmission lines. Like 

master meter pipeline systems, LPG 

systems are simple and tend to cover 

limited geographical areas. Further, we 

estimate each master meter and LPG 

system operator has, on average, 100 

services at low pressure. Very small 

operators with less than ten services and 

no portion of their systems in public 

areas will not be subject to the 

requirements of this proposed rule 

because these small operators are 

generally exempt from Part 192.14

PHMSA’s review of reported 

incidents shows few incidents occur in 

master meter and LPG systems. Because 

of the relative simplicity of these 

pipeline systems, a risk analysis would 

provide much less useful information 

than an analysis of a more complicated 

distribution system. Master meter 

operators often exercise more positive 

control over excavations near their 

pipelines, thereby providing enhanced 

protection from third-party damage, the 

leading cause of distribution system 

incidents. 

Based on this analysis and the 

distinctions that already exist in the 

regulations, the proposed rule would 

limit the scope of the IM requirements 

for master meter operators and LPG 

operators. Under the proposal, these 

operators would not have to perform 

risk analyses as part of their IM program 

because the relative simplicity of their 

systems makes the effort to perform the 

analysis more burdensome than 

beneficial. Additionally, these operators 

will not have to report performance 

measures, although they will need to 

maintain internal records of 

performance for inspection purposes. 

PHMSA invites public comment on 

the following: 

• Whether these IM limitations are 

appropriate for master meter and LPG 

system operators; 

• Whether we should further limit the 

IM requirements for these operators; or 

• Whether we should exempt these 

operators from IM requirements. 

B. Very Small Distribution Systems 

PHMSA notes there may be some 

local distribution systems of limited 

area and simple design for which 

similar limited IM requirements may be 

appropriate. There is currently no 

regulatory precedent for differentiating 

among local distribution systems to 

identify a class of operators to exempt 

from certain requirements. PHMSA 

would consider limiting IM 

requirements for other operators of 

small, simple systems if we can 

establish reasonable criteria to identify 

operators for which such limitations are 

appropriate. 

PHMSA does not consider the number 

of customers an appropriate selection 

criterion. Size, as measured by number 

of customers, is not directly correlated 

to risk. For example, a system serving 

several thousand customers that was 

installed over a brief period (e.g., after 

a transmission line was installed nearby 

providing a source of gas) could be quite 

uniform in design and materials. On the 

other hand, a system serving a few 

hundred customers that has been 

installed piecemeal over many years 

could have multiple types of material, 

including older materials subjected to 

age-related degradation, etc. In this 

example, the larger system would be 

expected to pose considerably less risk 

than the smaller. Rather than the 

system’s size, PHMSA considers that 

appropriate criteria would identify 

systems with characteristics similar to 

those of master meter systems and 

representative of low risk. PHMSA 

proposes the following basis for making 

this distinction: 

1. The system operates at a single 

pressure; 

2. The system may include valves, 

meters, and service pressure regulators, 

but no other equipment; 

3. The physical environment (i.e., 

potential for corrosion) is similar 

throughout the entire system; 

4. Most of the system was installed at 

one time, consisting of one material. 

Additions may have been made later of 

another material, but those additions are 

limited and their location is known; and 

5. The system location allows the 

operator to exercise control over most 

third-party excavation. 

PHMSA invites comment on whether 

limited IM requirements should also 

apply to operators of simple distribution 

pipeline systems and on whether the 

above criteria would be appropriate for 

identifying systems to which to apply 

this limitation. 

VIII. Plastic Pipe Issues 

A. Plastic Pipeline Database and 

Availability of Failure Information 

A significant amount of gas 

distribution pipeline is made of plastic. 

Very little plastic pipe is used in other 

pipeline systems. The Plastic Pipe Data 

Committee (PPDC), a voluntary group 

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36026 Federal Register / Vol. 73, No. 123 / Wednesday, June 25, 2008 / Proposed Rules 

consisting of representatives of industry, 

the NTSB, State pipeline safety 

regulators and PHMSA, and 

administered by the American Gas 

Association (AGA), monitors in-service 

performance of plastic pipe. 

Participating operators send information 

on problems occurring with plastic pipe 

and related fittings in their pipeline 

systems. PPDC periodically analyzes 

this information to identify adverse 

performance trends and problems 

potentially requiring action by plastic 

pipe users. PPDC information has 

limited distribution and is generally not 

available to operators who do not 

participate in the program. Gas 

distribution pipeline operators whose 

systems include significant amounts of 

plastic pipe would be better able to 

carry out an IM program with 

knowledge of plastic pipe performance 

issues. 

PHMSA believes changes to the PPDC 

process could significantly improve 

operator insight into the risks associated 

with plastic distribution pipelines. In 

particular, more data of better quality 

and improved availability of results 

from PPDC data analysis could help 

inform operators of potential integrity 

issues related to their plastic pipe. 

Changes PHMSA would consider 

valuable include the following: 

• Changing the current system of data 

collection, analysis, and communication 

to allow all operators better access to 

information on ‘‘suspect’’ materials in 

their systems (once analysis identifies a 

potential generic problem); 

• Adding new requirements to 

facilitate operator use of PPDC 

information; and 

• Adding requirements for 

information gathering on existing 

installed piping and equipment when 

normal operation and maintenance 

exposes the pipe. 

PHMSA intends to discuss with AGA 

how to strengthen the PPDC process and 

improve availability of results and to 

encourage AGA to continue related 

discussions with PPDC members. 

PHMSA also invites public comment as 

to whether the PPDC, administered by 

AGA, is adequately objective to evaluate 

and report to the industry information 

concerning plastic pipe failures, or 

whether PHMSA should seek a new 

independent third party to perform this 

function. 

PPDC is an independent entity. 

PHMSA cannot dictate the actions that 

PPDC takes. PPDC may not agree to 

changes that would provide information 

to operators who do not participate, and 

who cannot now include in their 

analyses failures that occur at nonparticipating operators. Further, it is 

uncertain whether a different 

independent third party can be 

identified that would be willing and 

able to assume the task of analyzing 

failure information. Given the 

importance of plastic pipe integrity to 

distribution pipeline system safety, 

PHMSA has included in this proposed 

rule requirements for all operators to 

report data on failures that occur in 

plastic pipe/fittings. We are proposing 

that reports be made within 90 days of 

the occurrence of a failure. PHMSA will 

collect the data and ensure that the data 

are analyzed and that appropriate 

insights are communicated to all 

distribution pipeline operators for their 

consideration as part of their integrity 

management programs. PHMSA may 

take additional actions if analysis of 

reported failures indicates additional 

regulatory action is appropriate. 

PHMSA is proposing that a report be 

submitted within 90 days because we 

consider 90 days to be reasonable time 

for conducting detailed failure cause 

analysis. PHMSA invites public 

comment on whether some other 

reporting frequency is preferable and 

adequate to identify trends (e.g., 

quarterly reporting, annual reporting). 

The proposed requirements to collect 

and report data on plastic pipe failures 

from the final rule may not be necessary 

if another group agrees to perform these 

functions. PHMSA invites comments on 

the appropriateness of the proposed 

reporting requirements. 

B. Plastic Pipe Marking 

Having better information on pipe 

type and its history would improve 

operators’ ability to manage their risk. In 

many cases, records are inadequate to 

determine exactly what type of pipe is 

installed in particular locations in 

distribution systems. It would be 

convenient if pipe was marked so that 

operators could collect this information 

by examining the pipe when it is 

excavated for other reasons. 

Unfortunately, plastic pipe has not 

historically included any permanent 

markings that would allow operators to 

determine the particular type of plastic, 

its age, or other key parameters. 

PHMSA recognizes there are many 

technical issues associated with pipe 

marking, and developing solutions 

requires discussion with all affected 

organizations. Technical issues include 

the label contents, durability, size, 

visibility, and spacing. PHMSA plans to 

discuss these issues further with 

pipeline manufacturers, operators, AGA, 

and State pipeline safety regulators. 

Thereafter, PHMSA plans to ask the 

American Society of Testing and 

Materials (ASTM) to revise its current 

standard for plastic pipe marking (i.e., 

ASTM D2513). PHMSA could then 

consider incorporating the standards 

into federal regulations. 

PHMSA invites comments on the 

desirability of requiring permanent 

markings on plastic pipe, on the related 

technical and logistical issues, and on 

its proposed approach to rely on ASTM 

to establish appropriate standards. 

IX. Monitoring the Effectiveness of 

Actions 

It is important that any program 

intended to improve safety include 

measurable attributes that can 

demonstrate whether the program is 

being effective. The existing IMP 

requirements for hazardous liquid and 

gas transmission pipelines both require 

operators to monitor performance and to 

review their programs periodically to 

determine if there is a need to change. 

This proposed rule contains similar 

requirements for distribution pipeline 

system operators. Similarly, it is 

important for PHMSA to be able to 

measure whether its actions are having 

the desired effect—improved safety. 

The ultimate measure of distribution 

pipeline system safety is the number of 

deaths and injuries and the amount of 

property damage caused by incidents on 

distribution pipeline systems. 

Fortunately, however, incidents occur 

relatively infrequently. The number of 

deaths and injuries and the amount of 

damage are thus lagging indicators of 

performance that cannot reliably 

capture safety trends other than over 

long periods of time. Other interim 

measures are needed to provide 

information in a shorter period to 

evaluate the effectiveness of any new 

integrity management requirements 

implemented for distribution pipeline 

systems. This proposed rule requires 

that distribution pipeline operators 

submit to PHMSA annually the number 

of leaks repaired (by cause), the number 

of excavation damages and the number 

of ‘‘tickets’’ (representative of the 

amount of excavation activity), and the 

number of EFVs installed. PHMSA will 

use these data to evaluate the 

effectiveness of new distribution 

integrity management requirements 

until sufficient time has passed that 

trends in the overall number of 

incidents, deaths, serious injuries, and 

property damage should be apparent. 

PHMSA solicits comments on whether 

the paperwork burdens associated with 

the collection of this data is justified by 

the usefulness of this information. 

PHMSA also invites comment on other 

measures that might be used to monitor 

effectiveness in this interim period. 

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Federal Register / Vol. 73, No. 123 / Wednesday, June 25, 2008 / Proposed Rules 36027 

15Operators are currently required to take the 

following periodic actions: 

1. Cathodic Protection (CP) must be tested once 

per year. Rectifiers and moving/active components 

must be inspected six times per year (192.465) 

2. Operators must reevaluate pipelines without 

CP every 3 years and provide CP if active corrosion 

is found (192.465) 

3. Pipe exposed to the atmosphere must be 

inspected for corrosion every 3 years (§ 192.481) 

4. Leak surveys must be conducted annually in 

business districts and at least every 5 years (3 if 

cathodically unprotected and electrical surveys are 

impractical) outside of business districts (§ 192.723) 

5. Pressure limiting devices must be tested at 

least annually (§ 192.739) 

6. Each valve necessary for safe system operation 

must be tested annually (§ 192.747) 

7. Vaults housing pressure regulating equipment 

must be inspected annually (§ 192.749) 

8. Mains must be patrolled 4 times a year in 

business districts and twice per year outside 

business districts (§ 192.721) 

X. Deviating From Required Intervals 

Based on Operator’s DIMP 

The underlying purpose of all of 

PHMSA’s integrity management 

requirements is to improve knowledge 

of the condition of each operator’s 

pipeline and to use that information to 

identify new risk control solutions and 

to better focus risk reduction efforts. 

PHMSA concludes, based on our 

experience with hazardous liquid and 

gas transmission integrity management, 

that this process is working and is 

producing a more efficient and effective 

approach to controlling pipeline risk. 

PHMSA considers that implementing 

integrity management for distribution 

pipelines should offer additional 

opportunities to improve efficiency in 

assuring safety. Improving efficiency in 

assuring safety requires, however, that it 

be possible to reduce efforts that have 

marginal effect on controlling risk in 

order to shift resources to more effective 

actions. 

As part of our continuing effort to 

improve efficiency and to make the 

approach to pipeline safety more riskbased, we are proposing an approach 

that would allow operators and the 

States to have more of a role in setting 

compliance intervals for distribution 

operators within a state. Rather than 

continue to require distribution 

operators to comply with intervals set 

by existing federal regulation in Part 

192, this approach would let an operator 

use its distribution integrity plan, and 

the risk assessment on which it is based, 

to propose alternative intervals for Part 

192 requirements that they must now 

implement periodically.15 Operators 

could propose extended intervals for 

threats and areas (e.g., portions of 

pipeline systems) where risk is low, 

making the application of these 

requirements more risk-based. 

Operators would be required to 

submit their proposed intervals to the 

jurisdictional regulatory authority 

(usually the State) for review and 

determination that the proposal will 

provide an adequate level of pipeline 

safety. States would base their decisions 

on their review of the operator’s risk 

analysis and on their own knowledge of 

the safety performance of, and issues 

affecting, each operator. While operators 

would likely propose only longer 

intervals, States could exercise their 

existing authority to impose 

requirements more restrictive than 

Federal minimums to require shorter 

intervals where necessary based on risk. 

PHMSA intends to work with NAPSR to 

develop guidance States can use in 

making decisions concerning changes to 

the intervals for periodic requirements. 

As an example, operators are now 

required to inspect pipelines potentially 

subject to atmospheric corrosion, 

including service lines entering 

customer gas meters, at least every three 

years. Many meters are located inside 

homes where, in many cases, no one is 

available during the day to provide 

access, and where the environment is 

unlikely to be particularly corrosive. 

Operators must arrange with residents 

for access, and must sometimes make 

multiple visits in order to complete 

their inspections. The industry is 

seeking regulatory changes based on 

these difficulties to reduce the 

frequency of required inspections of 

inside meters. An alternative approach 

might be for operators to establish that 

corrosion of pipelines in residences is 

low-risk, and to propose an alternate 

interval for conducting these 

inspections. States would have the 

flexibility to accept or modify operator 

adjustments to these inspection 

intervals based on their local 

circumstances and their understanding 

of operators’ risk. 

We seek comment on the following 

issues: 

• What are the advantages and 

disadvantages of allowing operators and 

States to set intervals for each 

distribution operator on required 

activities using a risk-based approach 

driven by thorough analysis of 

individual operator performance data? 

• Should there be some limit on the 

amount by which an operator can 

deviate from currently-prescribed 

intervals (e.g., no more than twice the 

interval in the Federal regulation)? 

• How would a State establish 

guidance for implementing such a 

process? 

• What additional performance data 

and analysis would be required? 

• What costs to the States would be 

associated with such a process? 

• What cost savings to operators 

could result from such changes? 

• On what basis should a State judge 

the operators’ engineering basis 

adequate? 

XI. Prevention Through People 

Historically, PHMSA’s pipeline 

integrity management programs have 

focused on assuring the physical and 

structural soundness of the pipe. This is 

a key element to the safe transportation 

of hazardous materials, including 

transportation by pipeline. However, it 

is only part of the safety picture. The 

role of people, including control center 

operators, in preventing and reducing 

risk is another critical component in 

managing the integrity of pipeline 

systems, including distribution piping. 

The proposed IM program regulations 

include requirements for operators to 

understand the threats affecting the 

integrity of their systems and to 

implement appropriate actions to 

mitigate risks associated with these 

threats. These include a first step 

towards instituting a ‘‘Prevention 

through People’’ (PTP) program to 

address human impacts on pipeline 

system integrity. Human impacts 

include both errors contributing to 

events and intervention to prevent or 

mitigate events. As part of considering 

the threat of inappropriate operation 

(i.e., inappropriate actions by people), 

this proposed rule would have operators 

evaluate the potential for human error, 

considering existing regulatory 

programs (e.g. Operator Qualification, 

Drug and Alcohol Testing, Damage 

Prevention, Public Education) , and any 

voluntary supplemental programs the 

operator now implements, in preventing 

and mitigating risk. An operator would 

be required to include in its written IM 

program a separate section on ‘‘Assuring 

Individual Performance,’’ in which they 

would identify risk management 

measures to evaluate and manage the 

contribution of human error and 

intervention to risk (e.g., changes to the 

role or expertise of people). 

Several existing regulations 

strengthen the effectiveness of the role 

of people in managing safety. These 

include Damage Prevention Program in 

§ 192.614, Public Awareness in 

§ 192.616, Qualification of Pipeline 

Personnel in subpart N under Part 192, 

and drug and alcohol testing in Part 199. 

The evaluation required by this 

proposed rule would consider the 

effects of these programs, and a PTP 

program would integrate these existing 

efforts and would address the risks 

associated with human factors as 

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36028 Federal Register / Vol. 73, No. 123 / Wednesday, June 25, 2008 / Proposed Rules 

enumerated in Section 12 of the PIPES 

Act, as well as the opportunities for 

people to mitigate risks. PHMSA is 

separately developing proposed 

requirements for control room 

management, which would also become 

a part of the PTP program and a 

consideration for integrity management 

of distribution pipeline systems. 

A PTP program could include 

regulations and a system to identify and 

communicate noteworthy best practices. 

Because human interaction with gas 

distribution systems contributes to the 

risk these systems pose, PHMSA 

believes a PTP effort has strong 

potential to reduce distribution system 

risk. PHMSA invites public comment on 

the PTP concept and on any other 

requirements that should be included in 

this or a future IM program rulemaking. 

PHMSA also requests public comment 

on how operators are currently 

addressing human factors, including 

fatigue, in their ongoing efforts to 

manage the integrity of their 

distribution pipelines. 

XII. Summary Description of Proposed 

Rule 

Over the past eight years, more than 

1,000 incidents on distribution 

pipelines have resulted in fatalities, 

serious injuries, or major property 

damage. Excavation damage and other 

outside forces caused most of these 

incidents. This proposal reduces system 

operating risks and the probability of 

failure by requiring operators to 

establish a documented, systematic 

approach to evaluating and managing 

risks associated with their pipeline 

systems. In this NPRM, PHMSA 

proposes to add a new subpart to the 

Federal pipeline safety regulations to 

require gas distribution pipeline 

operators to develop and implement IM 

programs covering the seven IM 

program elements identified by PHMSA 

and representatives of States, industry, 

and the public who participated in the 

stakeholder groups. The proposed rule 

also implements the legislative direction 

that PHMSA prescribe minimum 

standards for IM programs for 

distribution pipelines. As discussed 

above, PHMSA requested GPTC to 

develop more detailed guidance to assist 

distribution operators in implementing 

a new rule and States in overseeing 

these requirements. 

The proposed regulation would 

require operators to develop and 

implement written IM programs 

addressing the following elements: 

• Knowledge of infrastructure; 

• Identification of threats; 

• Evaluation and prioritization of 

risks; 

• Mitigation of risks; 

• Measurement and monitoring of 

performance; 

• Periodic evaluation and 

improvement; and 

• Reporting of results. 

The proposed rule implements the 

legislative direction that PHMSA 

require distribution pipeline operators 

to install an EFV in each newlyinstalled or replaced service line serving 

a single-family residence for which a 

suitable valve is commercially-available 

and where conditions are suitable. 

Suitable conditions include: 

• Operation continuously throughout 

the year at a pressure not less than 10 

psig; 

• No history of liquids or 

contaminants in the gas flow which 

would interfere with operation of the 

valve; and 

• Where installation is not likely to 

cause a loss of service to the residence; 

or 

• Interfere with required operation 

and maintenance activities. 

Any installation will have to comply 

with the performance standards in 

§ 192.381. The proposed requirement to 

install EFVs will make it unnecessary 

for operators to notify customers of EFV 

availability as currently required by 

§ 192.383. Thus, this proposal would 

repeal the customer notification 

requirement. 

Because of the significant diversity 

among distribution pipeline operators 

and systems, the IM requirements in the 

proposed rule are high-level and 

performance-based. The proposal 

specifies the required program elements, 

but does not prescribe specific methods 

of implementation. Prescriptive, how-to 

requirements would likely not fit the 

circumstances of all operators. Still, 

PHMSA recognizes many operators will 

want additional detail about actions 

they may take to implement the 

performance-based regulatory 

requirements. This is the reason 

PHMSA asked GPTC to develop 

guidance providing examples of 

methods that satisfy the requirements. 

Also, as discussed earlier, the APGA SIF 

intends to use the GPTC guidance to 

develop model IM programs for its small 

municipal members. 

XIII. Section-by-Section Analysis 

Section 192.383 Excess flow valve 

customer notification. This section 

currently requires operators to notify 

customers about EFV availability for 

installation and install an EFV if the 

customer so requests and agrees to bear 

all associated costs. The proposed 

requirements in this NPRM would 

require operators to install EFVs in new 

or replaced service lines unless certain 

conditions preclude installation. We are 

repealing this existing requirement 

because the proposed new requirements 

render the notification requirements in 

this section unnecessary. 

Section 192.1001 What do the 

regulations in this subpart cover? These 

proposed rules will apply to all 

operators of gas distribution systems 

subject to Part 192. The proposed rules 

would require each operator of a 

distribution pipeline system to 

implement an IM program with 

prescribed minimum requirements. 

Under the proposal, IM requirements 

applicable to master meter operators 

and operators of liquid propane gas 

(LPG) distribution systems will be much 

more limited than those applicable to 

larger operators. For example, the 

proposal would not require these 

operators to install EFVs and would not 

have them evaluate and prioritize risks 

and report results. 

Section 192.1003 What definitions 

apply to this subpart? PHMSA proposes 

to add a definition for the term 

‘‘damage’’ as used in § 192.1005. 

Section 192.1005 What must a gas 

distribution operator (other than a 

master meter or LPG operator) do to 

implement this subpart? The proposed 

rule would require gas distribution 

operators, other than master meter or 

LPG distribution system operators (see 

§ 192.1015), to develop a formal IM 

program with certain prescribed 

elements and to implement their 

programs no later than 18 months after 

the final rule becomes effective. The IM 

program is to manage and reduce the 

risks associated with the operator’s 

pipeline system. 

Section 192.1007 What are the 

required IM program elements? The 

proposed rule defines the minimum 

elements each operator’s IM program 

must include. Master meter and LPG 

operators will include only some 

elements in their programs. For gas 

distribution operators other than master 

meter or LPG operators, the required 

program elements are as follows: 

a. Knowledge of the system’s 

infrastructure. To develop an IM 

program, an operator must identify 

threats applicable to its pipeline system 

and analyze the risks its pipeline system 

poses. Operators cannot do this without 

understanding their pipeline systems. 

Generally, the operator should know 

information such as location, material 

composition, piping sizes, construction 

methods, date of installation, soil 

conditions, pressure (operating and 

design), operating experience, 

performance data, condition of the 

system, and any other characteristics 

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16 Integrity Management for Gas Distribution, 

Report of Phase 1 Investigations, December 2005, 

Attachment 4, page 18. Based on data reported to 

PHMSA by distribution pipeline operators for 2004. 

that help identify the applicable threats 

and risks. 

An operator may not know some 

necessary information about its 

infrastructure. In some cases, 

distribution systems include pipe 

installed several decades ago, and 

reliable records may not exist to provide 

complete information. In other cases, 

distribution systems have grown by 

acquisition and merger, as multiple 

pipeline systems came under common 

ownership. Complete records may not 

have been transferred during these 

changes in ownership, again leading to 

gaps in the knowledge an operator has 

about its pipeline system. This proposed 

rule does not require operators to engage 

in extensive investigative programs to 

uncover information, nor does it require 

operators to conduct excavations for the 

sole purpose of revealing information 

about buried pipe. 

An operator must assemble as 

complete an understanding of its 

infrastructure as possible using 

information the operator has on hand 

from ongoing design, operations, and 

maintenance activities. An operator’s IM 

program must identify what additional 

information the operator needs to know 

about its infrastructure, and must 

provide for gaining that additional 

knowledge over time through normal 

activities. For example, situations in 

which buried pipe must be exposed for 

maintenance or other purposes present 

an opportunity to collect data about the 

pipe and its environment at very little 

or no additional cost. An operator’s IM 

program must provide for identification 

and use of such opportunities to 

improve knowledge of the distribution 

system infrastructure. 

b. Identify threats (existing and 

potential). Operators need to evaluate 

their pipeline systems and the 

environments in which the pipelines 

operate to identify specific threats the 

pipelines face and to determine what 

are appropriate actions to manage the 

threats and minimize the risk. Threats 

affecting pipeline systems are generally 

grouped into broad categories. This 

proposed rule uses the same categories 

as does the form operators use to report 

incidents occurring on their distribution 

pipeline systems (Form PHMSA F 

7100.1). Not all threat categories are 

applicable to all pipelines. For example, 

corrosion does not affect plastic pipe. 

Additionally, the categories often 

represent a grouping of similar threats, 

not all of which may affect a given 

pipeline. Although all buried metal pipe 

is generally considered subject to 

potential external corrosion, not all 

pipeline systems are subject to internal 

corrosion. Outside force may be an 

applicable threat, but outside force from 

earthquake movement may or may not 

be an issue. The proposed rule would 

require operators to identify both 

existing threats and potential threats. 

For example, outside force from 

landslide or earth movement may be a 

potential threat to a distribution 

pipeline system servicing an expanding 

community, even though currently, the 

pipeline system is not affected by such 

problems. 

In considering the threat of 

inappropriate operation, operators 

would be required to evaluate the effects 

that actions of its personnel can have on 

pipeline safety. 

c. Evaluate and prioritize risk. Simply 

knowing what threats exist is not 

sufficient to understand and manage 

risk posed to distribution pipeline 

systems. Operators must determine the 

likelihood that a system failure would 

be caused by any given threat. 

Therefore, the proposed rule would 

require operators to evaluate each 

applicable threat and estimate the risk 

to the pipeline. An operator may 

subdivide the system into regions (areas 

within a distribution system consisting 

of mains, services and other 

appurtenances) with similar 

characteristics and reasonably 

consistent risk, and for which similar 

actions would be effective in reducing 

risk. 

d. Identify and implement measures 

to address risks. Once the relative risks 

are known, operators can take action to 

mitigate those risks and thus improve 

safety. The specific actions appropriate 

for an operator to take will vary 

depending on the applicable threats, 

their prevalence, and the risks posed by 

a leak or failure on the operator’s 

pipeline. 

The proposed rule would require 

operators to identify and implement 

appropriate risk reduction strategies. 

Under the proposal, operators would be 

required to implement at least two risk 

reduction strategies—an effective leak 

management program and an enhanced 

damage prevention program. Since 

excavation damage is the leading cause 

of incidents on gas distribution pipeline 

systems, having effective measures to 

minimize the likelihood of such damage 

would be a valuable risk reduction 

method. Low-pressure distribution 

pipelines tend to fail by leaking, except 

in some cases of excavation damage. 

Leaking gas tends to migrate and can 

accumulate in buildings and other 

confined areas where fires and 

explosion can result. Leaks can be 

identified and corrected before injury to 

people and property occurs. 

Distribution pipeline operators typically 

have established leak management 

programs. This is the reason, for 

example, why leaks resulting from 

corrosion represent 36 percent of leaks 

repaired on distribution mains and 25 

percent on service lines, while corrosion 

is the cause of less than five percent of 

distribution pipeline incidents.16 An 

effective leak management program is 

thus a valuable risk reduction strategy 

for all distribution pipeline operators. 

Each operator would be required to 

develop an IM program with a separate 

section on ‘‘Assuring Individual 

Performance’’ to improve the safety 

performance of its personnel. This is a 

first step towards implementing an 

integrated approach to assuring PTP. 

e. Measure performance, monitor 

results, and evaluate effectiveness. The 

proposed rule would require each 

operator to measure its performance and 

report certain measures periodically to 

PHMSA and State regulatory 

authorities. Only by measuring results 

can an operator know if its risk 

reduction efforts are effective. As 

proposed, operators would have to make 

changes to their programs to improve 

effectiveness if performance 

measurement indicates improvement is 

needed. Regulators will use the reported 

performance measures to evaluate 

overall effectiveness in reducing risk 

from gas distribution pipeline systems. 

Further changes to regulations or to 

oversight (e.g., frequency of inspections) 

may be appropriate depending on the 

data analysis findings. 

f. Periodic Evaluation and 

Improvement. Operators would use 

measured performance to determine 

whether further improvements are 

needed and to make necessary changes 

in their IM programs. Operators would 

have to evaluate their programs 

periodically. Operators should 

determine how often these reviews are 

appropriate. For large, complex systems, 

sufficient data and experience may be 

available to make annual reviews 

meaningful. For small, simple systems, 

there may not be sufficient information 

to make an annual review meaningful. 

Whatever the size of the system, all 

operators will have to conduct a 

complete program evaluation at least 

once every five years. 

g. Report results. The proposed rule 

would require each operator to measure 

its performance and report certain 

measures periodically to PHMSA and 

State regulatory authorities. The 

proposal would require operators to 

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36030 Federal Register / Vol. 73, No. 123 / Wednesday, June 25, 2008 / Proposed Rules 

report four of the required performance 

measures each March to PHMSA as part 

of the annual report required by 

§ 191.11. Combining this reporting with 

the annual report already required will 

minimize the additional burden on 

operators to provide this information. 

Operators would also be required to 

report these four measures to the State 

pipeline safety authority where the gas 

distribution pipeline is located. 

Operators also would be required to 

retain records of the remaining listed 

performance measures for ten years. 

Section 192.1009 What must an 

operator report when plastic pipeline 

fails? Plastic pipe (including fittings, 

couplings, valves and joints) forms a 

significant portion of many distribution 

pipeline systems. Plastic pipe is used 

very little in other pipeline systems. 

Knowledge of potential weaknesses in 

its plastic pipe is thus particularly 

important for a distribution pipeline 

operator analyzing the risk from its 

system. This section would require that 

operators report all plastic pipe failures 

to PHMSA within 90 days after a failure. 

PHMSA will collect this information 

and will assure that it is analyzed to 

identify and communicate significant 

information about potential 

vulnerabilities associated with plastic 

pipe. Distribution pipeline operators 

will then be able to take this 

information into consideration in their 

risk analyses. 

Section 192.1011 When must an 

Excess Flow Valve (EFV) be installed? 

Gas distribution operators, except for 

master meter and LPG operators, would 

be required to install an EFV in each 

new or replaced service line installed 

for a single-family residence if a suitable 

valve is commercially available and 

certain operating conditions are present 

for the EFV to function. The required 

operating conditions are: the operating 

pressure in the service line must be 10 

psig or greater; the gas stream must be 

free of contaminants and liquids 

potentially interfering with valve 

operation; installation must not result in 

loss of service to the residence; the 

presence of an EFV must not interfere 

with required operation and 

maintenance activities; and the EFV 

must meet the performance criteria 

listed in 49 CFR § 192.381. 

Section 192.1013 How does an 

operator file a report with PHMSA? This 

section describes where an operator is to 

send required reports. PHMSA prefers 

electronic submissions. 

Section 192.1015 What records must 

an operator keep? The proposed rule 

requires an operator to make a number 

of decisions and to perform a number of 

analyses to determine and implement 

risk reduction methods most 

appropriate to its distribution pipeline 

system. It is critical that an operator 

retain knowledge of the basis for its 

decisions for the operator to effectively 

implement and modify its IM program. 

The proposed rule specifies the records 

an operator would have to keep to serve 

this purpose. These records also will 

allow PHMSA (or the applicable State 

oversight agency) to review the 

operator’s analyses, decisions, and 

actions to determine through 

inspections if they are reasonable and 

comply with the proposed 

requirements. 

Section 192.1017 When may an 

operator deviate from required periodic 

inspections of this part? Various 

provisions of Part 192 require all 

distribution pipeline operators to 

perform actions at prescribed intervals. 

49 CFR 192.481, for example, requires 

all operators to perform atmospheric 

corrosion inspection at fixed three-year 

intervals, without regard to systemspecific risk factors. It is likely that 

some of these actions could be 

performed at less frequent intervals 

(based on lower risk) with no difference 

in safety outcomes. The resources made 

available by reducing action intervals, 

where appropriate, could be used to 

address more risk-significant problems. 

Thus, deviating from intervals now 

specified in other sections of Part 192 

could allow operators to be more riskbased in application of their resources. 

This section would allow operators to 

use their risk analyses to propose 

changes to the intervals for periodic 

requirements included in other sections 

of Part 192. Operators would be 

required to submit their proposals to 

jurisdictional safety regulators (usually 

States) for review and determination 

that the proposal will assure an 

adequate level of pipeline safety. 

Section 192.1019 What must a 

master meter or liquefied petroleum gas 

(LPG) operator do to implement this 

subpart? This section specifies the 

requirements master meter and LPG 

operators must meet. Gas distribution 

systems operated by master meter and 

LPG operators are subject to the 

requirements of Part 192, but these 

systems are generally smaller and pose 

less risk than systems operated by other 

gas distribution operators. Master meter 

and LPG systems cover a smaller 

geographic area, over which the 

operator usually has more control. In 

particular, the operator usually has 

more control over excavation activity, 

which is the leading cause of damage to 

gas distribution pipeline systems. To 

reflect these differences, we are 

proposing a more limited and simpler 

set of IM program requirements for these 

operators. They must develop and 

implement written IM programs 

containing the elements required of 

other gas distribution operators, except 

an IM program for a master meter or 

LPG operation need not include the 

elements for evaluating and prioritizing 

risks and reporting results. There will be 

no EFV installation requirements. Also, 

the level of detail in these IM programs 

should be much less to reflect the 

relative simplicity of these pipeline 

systems. In a separate guidance 

document, we will provide a model IM 

program these operators may use. A 

draft of this guidance is available in the 

docket to this rulemaking. We request 

comment on this draft guidance. 

Guidance. To carry out the proposed 

requirements, operators will have to 

make a number of reasonably complex 

decisions and analyses to understand 

their systems, evaluate threats and risks, 

and implement risk reduction methods. 

While it is impractical to specify a 

single method for how operators should 

make these decisions/analyses, it is 

possible to provide guidance concerning 

factors operators should consider This 

document will provide guidance in 

carrying out several requirements. 

PHMSA expects GPTC to develop more 

detailed guidance to assist operators in 

implementing a final rule. Once the 

GPTC guidance is available, PHMSA 

may modify the proposed guidance. 

This draft guidance document is 

available in the docket to this 

rulemaking 

XIV. Regulatory Analyses and Notices 

A. Statutory/Legal Authority for This 

Rulemaking 

This notice of proposed rulemaking is 

published under the authority of the 

Federal Pipeline Safety Law (49 U.S.C. 

60101 et seq.). Section 60102 authorizes 

the Secretary of Transportation to issue 

regulations governing design, 

installation, inspection, emergency 

plans and procedures, testing, 

construction, extension, operation, 

replacement, and maintenance of 

pipeline facilities. The proposed 

integrity management program 

regulations are issued under this 

authority and address the NTSB’s and 

DOT Inspector General’s 

recommendations. This rulemaking also 

carries out the mandates regarding 

distribution integrity management and 

excess flows valves under section 9 of 

the Pipeline Inspection, Protection, 

Enforcement, and Safety Act of 2006 

(Pub. L. 109–468, Dec. 29, 2006). 

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B. Executive Order 12866 and DOT 

Regulatory Policies and Procedures 

DOT considers this an ‘‘economically 

significant’’ regulatory action under 

section 3(f)(1) of Executive Order 12866 

(58 FR 51735; October 4, 1993). This 

NPRM is also significant under DOT’s 

regulatory policies and procedures (44 

FR 11034; February 26, 1979). PHMSA 

prepared a Draft Regulatory Evaluation 

for this NPRM and placed it in the 

public docket. 

The proposed requirements would 

affect an estimated 9,291 natural gas 

operators with a combined total of 

1,138,000 miles of mains and 

60,970,000 services. Of these operators, 

201 are local gas utilities with more 

than 12 thousand services, 1,090 are 

local gas utilities with 12 thousand or 

fewer services, and 8,000 are master 

meter and LPG systems. 

The monetized benefits resulting from 

the proposed rule are estimated to be 

$214 million per year. Those benefits 

include: 

• Reductions in the consequences of 

reportable incidents; 

• Reductions in the consequences of 

non-reportable incidents; 

• A reduction in the probability of a 

major catastrophic incident; 

• Reductions in lost natural gas; 

• Reductions in emergency response 

costs; 

• Reductions in evacuations; 

• Reductions in dig-ins impacting 

non-gas underground facilities; and 

• Elimination of the existing EFV 

notification requirement. 

The costs of the proposed rule are 

estimated to be $155.1 million in the 

first year and $104.1 million in each 

subsequent year. Those costs cover: 

• Development of an IMP; 

• Implementation of the IMP; 

• Mitigation of risks; 

• Reporting to PHMSA and State 

Regulators; 

• Recordkeeping; and 

• Management of the IMP. 

The analysis finds that, for those costs 

and benefits that can be quantified, the 

present value of net benefits are 

expected to be between $1.5 billion and 

$2.8 billion over a fifty year period after 

all of the requirements are 

implemented. Also significant is that 

the proposed rule is expected to be costeffective if it results in eliminating only 

approximately 14.5 percent of the 

societal costs associated with gas 

distribution systems. 

C. Regulatory Flexibility Act 

Under the Regulatory Flexibility Act 

(5 U.S.C. 601 et seq.) PHMSA must 

consider whether a rulemaking would 

have a significant effect on a substantial 

number of small entities. The proposed 

IM program requirements apply to gas 

distribution pipeline operators and 

require operators of gas distribution 

pipelines to develop and implement 

IMPs that will better assure the integrity 

of their pipeline systems. 

Many gas distribution pipeline 

operators meet the Small Business 

Administration’s small business 

definition of 500 or fewer employees for 

natural gas distribution operators under 

North American Industry Classification 

System (NAICS) 221210. PHMSA 

estimates that the proposed rule will 

affect 9,007 small operators. These small 

operators can be separated into two 

categories: (1) Local gas distribution 

utilities with 12,000 or fewer services 

and (2) master meter and LPG systems. 

PHMSA estimates there are 1,007 small 

operators among the local gas 

distribution utilities with 12,000 or 

fewer services and 8,000 master meter 

and LPG systems, all of which are small. 

Furthermore, PHMSA estimates the 

proposed rule will cost each local gas 

utility with 12,000 or fewer services on 

average approximately $40,000 in the 

first year and $17,000 in each 

subsequent year. PHMSA also estimates 

that the proposed rule will cost master 

meter and LPG systems on average 

approximately $3,000 in the first year 

and $1,000 in each subsequent year. 

PHMSA does not have information on 

the operators’ revenues and cannot 

estimate the economic impact the costs 

will have. The costs associated with the 

proposed rule may be significant for at 

least some of the small entities. 

Therefore, PHMSA believes that the 

proposed rule could result in a 

significant adverse economic impact for 

some of the smallest affected entities. 

PHMSA invites comments on these 

assumptions. 

PHMSA has tried to minimize costs 

for these small operators. As mentioned 

earlier, small operators’ IM programs 

will not have to include the elements for 

evaluating and prioritizing risks and for 

reporting results and there will be no 

EFV installation requirements. PHMSA 

is also providing a manual for small 

operators to guide their compliance 

with the proposed rule and PHMSA will 

continue to evaluate alternative 

methods of compliance that reduce the 

burden on small businesses while 

retaining an appropriate level of 

pipeline safety. Additionally, industry 

is undertaking a number of initiatives 

that will help small entities comply 

with the proposed rule, including the 

preparation of guidance materials and a 

model IM program for distribution 

pipeline operators. 

D. Paperwork Reduction Act 

The Paperwork Reduction Act of 1995 

(44 U.S.C. 3501 et seq.) addresses the 

collection of information by the Federal 

government from individuals, small 

businesses and State and local 

governments and seeks to minimize the 

burdens such information collection 

requirements might impose. A 

collection of information includes 

providing answers to identical questions 

posed to, or identical reporting or 

record-keeping requirements imposed 

on ten or more persons, other than 

agencies, instrumentalities, or 

employees of the United States. In 

accordance with the requirements of the 

Paperwork Reduction Act, agencies may 

not conduct or sponsor, and the 

respondent is not required to respond 

to, an information collection unless it 

displays a currently valid Office of 

Management and Budget (OMB) control 

number. PHMSA is requesting comment 

on a proposed information collection. 

PHMSA is also giving notice that the 

proposed collection of information has 

been submitted to OMB for review and 

approval. 

This NPRM proposes additional 

information collection requirements. 

Those requirements result from affected 

natural gas distribution system 

operators having to (1) prepare a 

distribution integrity management 

program (DIMP); (2) document their 

DIMP procedures and processes; (3) 

prepare periodic revisions to their IM 

programs; (4) keep records, and (5) 

report periodically to PHMSA and the 

States. PHMSA evaluated the NPRM, as 

required by the Paperwork Reduction 

Act of 1995 (44 U.S.C. 3507(d)), and 

believes the burden hours to industry 

resulting from the NPRM will be 

681,379 in the first year and 85,597 

hours in each subsequent year. Large 

and small operators will bear the largest 

share of the information collection 

burden. Master meter and Liquid 

Petroleum Gas system operators are 

estimated to require 20 hours each to 

comply in the first year and to make 

brief (less than 1⁄4 hour) updates to the 

initial information in subsequent years. 

Pursuant to 44 U.S.C. 3506(c)(2)(B), 

PHMSA solicits comments concerning: 

whether these information collection 

requirements are necessary for PHMSA 

to properly perform its functions, 

including whether the information has 

practical utility; the accuracy of 

PHMSA’s estimates of the burden of the 

information collection requirements; the 

quality, utility, and clarity of the 

information to be collected; and 

whether the burden of collecting 

information on those who are to 

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respond, including through the use of 

automated collection techniques or 

other forms of information technology, 

may be minimized. 

E. Executive Order 13084 

This NPRM has been analyzed under 

principles and criteria contained in 

Executive Order 13084 (‘‘Consultation 

and Coordination with Indian Tribal 

Governments’’). Because this NPRM 

does not significantly or uniquely affect 

communities of Indian tribal 

governments and does not impose 

substantial direct compliance costs, the 

funding and consultation requirements 

of Executive Order 13084 do not apply. 

F. Executive Order 13132 

PHMSA analyzed this NPRM under 

the principles and criteria contained in 

Executive Order 13132 (Federalism). 

PHMSA issues pipeline safety 

regulations applicable to interstate and 

intrastate pipelines. The requirements 

in this proposed rule apply to operators 

of distribution pipeline systems, 

primarily intrastate pipeline systems. 

Under 49 U.S.C. 60105, PHMSA cedes 

authority to enforce safety standards on 

intrastate pipeline facilities to a certified 

State authority. Thus, State pipeline 

safety regulatory agencies will be the 

primary enforcer of these safety 

requirements. Although some States 

have additional requirements that 

address IM issues, no State requires its 

distribution operators to have 

comprehensive IM programs similar to 

what we are proposing. Under 49 U.S.C. 

60107, PHMSA gives participating 

States grant money to carry out their 

pipeline safety enforcement programs. 

Although some States choose not to 

participate in the pipeline safety grant 

program, every State has the option to 

participate. This grant money is used to 

defray added safety program costs 

incurred by enforcing the proposed 

requirements. We expect to increase 

money available to help States. 

PHMSA has concluded this proposed 

rule does not propose any regulation 

that: (1) Has substantial direct effects on 

States, relationships between the 

national government and the States, or 

distribution of power and 

responsibilities among various levels of 

government; (2) imposes substantial 

direct compliance costs on States and 

local governments; or (3) preempts State 

law. Therefore, the consultation and 

funding requirements of Executive 

Order 13132 (64 FR 43255; August 10, 

1999) do not apply. 

This proposed rule would serve to 

preempt any currently established State 

requirements in this area. States would 

have the ability to augment pipeline 

safety requirements for pipelines, but 

would not be able to approve safety 

requirements less stringent than those 

contained within this proposed rule. 

Although the consultation 

requirements do not apply, the States 

have played an integral role in helping 

develop the proposed requirements. 

State pipeline safety regulatory agencies 

participated in the stakeholder groups 

that helped develop the findings on 

which this proposal is based and 

provided guidance through NARUC in 

the form of a resolution. PHMSA action 

is consistent with this resolution. 

G. Executive Order 13211 

This NPRM is not a ‘‘significant 

energy action’’ under Executive Order 

13211 (Actions Concerning Regulations 

That Significantly Affect Energy Supply, 

Distribution, or Use). It is not likely to 

have a significant adverse effect on 

supply, distribution, or energy use. 

Further, the Office of Information and 

Regulatory Affairs has not designated 

this NPRM as a significant energy 

action. 

H. Unfunded Mandates 

PHMSA estimates that this NPRM 

does impose an unfunded mandate 

under the 1995 Unfunded Mandates 

Reform Act (UMRA). PHMSA estimates 

the rule to cost operators $155.1 million 

in the first year of the regulations, 

which is higher than the $100 million 

threshold (adjusted for inflation, 

currently estimated to be $132 million) 

in any one year. The Regulatory Impact 

Analysis performed under EO 12866 

requirements also meets the analytical 

requirements under UMRA, and 

PHMSA has concluded the approach 

taken in this regulation is the least 

burdensome alternative for achieving 

the NPRM’s objectives. 

I. National Environmental Policy Act 

PHMSA analyzed this NPRM in 

accordance with section 102(2)(c) of the 

National Environmental Policy Act (42 

U.S.C. 4332), the Council on 

Environmental Quality regulations (40 

CFR 1500–1508), and DOT Order 

5610.1C, and has preliminarily 

determined this action will not 

significantly affect the quality of the 

human environment. The 

Environmental Assessment is in the 

Docket. 

List of Subjects in 49 CFR Part 192 

Integrity management, Pipeline safety, 

Reporting and recordkeeping 

requirements. 

In consideration of the foregoing, 

PHMSA proposes to amend part 192 of 

title 49 of the Code of Federal 

Regulations as follows: 

PART 192—TRANSPORTATION OF 

NATURAL AND OTHER GAS BY 

PIPELINE: MINIMUM FEDERAL 

SAFETY STANDARDS 

1. The authority citation for part 192 

continues to read as follows: 

Authority: 49 U.S.C. 5103, 60102, 60104, 

60108, 60109, 60110, 60113, and 60118; and 

49 CFR 1.53. 

§ 192.383 [Removed] 

2. Section 192.383 is removed. 

3. In part 192, a new subpart P is 

added to read as follows: 

Subpart P—Gas Distribution Pipeline 

Integrity Management (IM) 

Sec. 

192.1001 What do the regulations in this 

subpart cover? 

192.1003 What definitions apply to this 

subpart? 

192.1005 What must a gas distribution 

operator (other than a master meter or 

LPG operator) do to implement this 

subpart? 

192.1007 What are the required integrity 

management (IM) program elements? 

192.1009 What must an operator report 

when plastic pipe fails? 

192.1011 When must an Excess Flow Valve 

(EFV) be installed? 

192.1013 How does an operator file a report 

with PHMSA? 

192.1015 What records must an operator 

keep? 

192.1017 When may an operator deviate 

from required periodic inspections under 

this part? 

192.1019 What must a master meter or 

liquefied petroleum gas (LPG) operator 

do to implement this subpart? 

Subpart P—Gas Distribution Pipeline 

Integrity Management (IM) 

§ 192.1001 What do the regulations in this 

subpart cover? 

General. This subpart prescribes 

minimum requirements for an IM 

program for any gas distribution 

pipeline covered under this part. A gas 

distribution operator, other than a 

master meter or liquefied petroleum 

(LPG) operator, must follow the 

requirements in §§ 192.1005 through 

192.1017 of this subpart. A master meter 

operator or LPG operator of a gas 

distribution pipeline must follow the 

requirements in § 192.1019 of this 

subpart. 

§ 192.1003 What definitions apply to this 

subpart? 

The following definitions apply to 

this subpart: 

Damage means any impact or 

exposure resulting in the repair or 

replacement of an underground facility, 

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related appurtenance, or materials 

supporting the pipeline. 

§ 192.1005 What must a gas distribution 

operator (other than a master meter or LPG 

operator) do to implement this subpart? 

(a) Dates. No later than [INSERT 

DATE 18 MONTHS AFTER 

PUBLICATION OF THE FINAL RULE 

IN THE Federal Register] an operator of 

a gas distribution pipeline must develop 

and fully implement a written IM 

program. The IM program must contain 

the elements described in § 192.1007. 

(b) Procedures. An operator’s program 

must have written procedures 

describing the processes for developing, 

implementing and periodically 

improving each of the required 

elements. 

§ 192.1007 What are the required integrity 

management (IM) program elements? 

(a) Knowledge. An operator must 

demonstrate an understanding of the gas 

distribution system. 

(1) Identify the characteristics of the 

system and the environmental factors 

that are necessary to assess the 

applicable threats and risks to the gas 

distribution system. 

(2) Understand the information gained 

from past design and operations. 

(3) Identify additional information 

needed and provide a plan for gaining 

that information over time through 

normal activities. 

(4) Develop a process by which the 

program will be continually refined and 

improved. 

(5) Provide for the capture and 

retention of data on any piping system 

installed after the operator’s IM program 

becomes effective. The data must 

include, at a minimum, the location 

where the new piping and 

appurtenances are installed and the 

material of which they are constructed. 

(b) Identify threats. The operator must 

consider the following categories of 

threats to each gas distribution pipeline: 

corrosion, natural forces, excavation 

damage, other outside force damage, 

material or weld failure, equipment 

malfunction, inappropriate operation, 

and any other concerns that could 

threaten the integrity of the pipeline. An 

operator must gather data from the 

following sources to identify existing 

and potential threats: incident and leak 

history, corrosion control records, 

continuing surveillance records, 

patrolling records, maintenance history, 

and ‘‘one call’’ and excavation damage 

experience. In considering the threat of 

inappropriate operation, the operator 

must evaluate the contribution of 

human error to risk and the potential 

role of people in preventing and 

mitigating the impact of events 

contributing to risk. This evaluation 

must also consider the contribution of 

existing DOT requirements applicable to 

the operator’s system (e.g., Operator 

Qualification, Drug and Alcohol 

Testing) in mitigating risk. 

(c) Evaluate and prioritize risk. An 

operator must evaluate the risks 

associated with its distribution pipeline 

system. In this evaluation, the operator 

must determine the relative probability 

of each threat and estimate and 

prioritize the risks posed to the pipeline 

system. This evaluation must consider 

each applicable current and potential 

threat, the likelihood of failure 

associated with each threat, and the 

potential consequences of such a failure. 

An operator may subdivide the system 

into regions (areas within a distribution 

system consisting of mains, services and 

other appurtenances) with similar 

characteristics and reasonably 

consistent risk, and for which similar 

actions would be effective in reducing 

risk. 

(d) Identify and implement measures 

to address risks. Determine and 

implement measures designed to reduce 

the risks from failure of its gas 

distribution pipeline system. These 

measures must include implementing 

an effective leak management program 

and enhancing the operator’s damage 

prevention program required under 

§ 192.614 of this part. To address risks 

posed by inappropriate operation, an 

operator’s written IM program must 

contain a separate section with a 

heading ‘Assuring Individual 

Performance’. In that section, an 

operator must list risk management 

measures to evaluate and manage the 

contribution of human error and 

intervention to risk (e.g., changes to the 

role or expertise of people), and 

implement measures appropriate to 

address the risk. In addition, this 

section of the written IM program must 

consider existing programs the operator 

has implemented to comply with 

§ 192.614 (damage prevention 

programs); § 192.616 (public awareness); 

Subpart N of this Part (qualification of 

pipeline personnel), and 49 CFR Part 

199 (drug and alcohol testing). 

(e) Measure performance, monitor 

results, and evaluate effectiveness. 

(1) Develop and monitor performance 

measures from an established baseline 

to evaluate the effectiveness of its IM 

program. An operator must consider the 

results of its performance monitoring in 

periodically re-evaluating the threats 

and risks. These performance measures 

must include the following: 

(i) Number of hazardous leaks either 

eliminated or repaired, per § 192.703(c), 

categorized by cause; 

(ii) Number of excavation damages; 

(iii) Number of excavation tickets 

(receipt of information by the 

underground facility operator from the 

notification center); 

(iv) Number of EFVs installed; 

(v) Total number of leaks either 

eliminated or repaired, categorized by 

cause; 

(vi) Number of hazardous leaks either 

eliminated or repaired per § 192.703(c), 

categorized by material; and 

(vii) Any additional measures to 

evaluate the effectiveness of the 

operator’s program in controlling each 

identified threat. 

(f) Periodic Evaluation and 

Improvement. An operator must 

continually re-evaluate threats and risks 

on its entire system and consider the 

relevance of threats in one location to 

other areas. In addition, each operator 

must periodically evaluate the 

effectiveness of its program for assuring 

individual performance to reassess the 

contribution of human error to risk and 

to identify opportunities to intervene to 

reduce further the human contribution 

to risk (e.g., improve targeting of damage 

prevention efforts). Each operator must 

determine the appropriate period for 

conducting complete program 

evaluations based on the complexity of 

its system and changes in factors 

affecting the risk of failure. An operator 

must conduct a complete program reevaluation at least every five years. The 

operator must consider the results of the 

performance monitoring in these 

evaluations. 

(g) Report results. Report the four 

measures listed in paragraphs (e)(1)(i) 

through (e)(1)(iv) of this section, 

annually by March 15, to PHMSA as 

part of the annual report required by 

§ 191.11 of this chapter. An operator 

also must report these four measures to 

the State pipeline safety authority in the 

State where the gas distribution pipeline 

is located. 

§ 192.1009 What must an operator report 

when plastic pipe fails? 

Each operator must report information 

relating to each material failure of 

plastic pipe (including fittings, 

couplings, valves and joints) no later 

than 90 days after failure. This 

information must include, at a 

minimum, location of the failure in the 

system, nominal pipe size, material 

type, nature of failure including any 

contribution of local pipeline 

environment, pipe manufacturer, lot 

number and date of manufacture, and 

other information that can be found in 

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markings on the failed pipe. An operator 

must send the information report as 

indicated in § 192.1013. An operator 

must also report this information to the 

State pipeline safety authority in the 

State where the gas distribution pipeline 

is located. 

§ 192.1011 When must an Excess Flow 

Valve (EFV) be installed? 

(a) General requirements. This section 

only applies to new or replaced service 

lines serving single-family residences. 

An EFV installation must comply with 

the requirements in § 192.381. 

(b) Installation required. The operator 

must install an EFV on the service line 

installed or entirely replaced after 

[INSERT DATE 90 DAYS AFTER 

PUBLICATION OF THE FINAL RULE 

IN THE Federal Register], unless one or 

more of the following conditions is 

present: 

(1) The service line does not operate 

at a pressure of 10 psig or greater 

throughout the year; 

(2) The operator has prior experience 

with contaminants in the gas stream that 

could interfere with the EFV’s operation 

or cause loss of service to a residence; 

(3) An EFV could interfere with 

necessary operation or maintenance 

activities, such as blowing liquids from 

the line; or 

(4) An EFV meeting performance 

requirements in § 192.381 is not 

commercially available to the operator. 

§ 192.1013 How does an operator file a 

report with PHMSA? 

An operator must send any 

performance report required by this 

subpart to the Information Resource 

Manager as follows: 

(a) Through the online electronic 

reporting system available at PHMSA’s 

home page at http://phmsa.dot.gov; 

(b) Via facsimile to (202) 493–2311; or 

(c) Mail: PHMSA—Information 

Resource Manager, U.S. Department of 

Transportation-East Building, 1200 New 

Jersey Avenue, SE., Washington, DC 

20590. 

§ 192.1015 What records must an operator 

keep? 

Except for the performance measures 

records required in § 192.1007, an 

operator must maintain, for the useful 

life of the pipeline, records 

demonstrating compliance with the 

requirements of this subpart. At a 

minimum, an operator must maintain 

the following records for review during 

an inspection: 

(a) A written IM program in 

accordance with § 192.1005; 

(b) Documents supporting threat 

identification; 

(c) A written procedure for ranking 

the threats; 

(d) Documents to support any 

decision, analysis, or process developed 

and used to implement and evaluate 

each element of the IM program; 

(e) Records identifying changes made 

to the IM program, or its elements, 

including a description of the change 

and the reason it was made; and 

(f) Records on performance measures. 

However, an operator must only retain 

records of performance measures for ten 

years. 

§ 192.1017 When may an operator deviate 

from required periodic inspections under 

this part? 

(a) An operator may propose to reduce 

the frequency of periodic inspections 

and tests required in this part on the 

basis of the engineering analysis and 

risk assessment required by this subpart. 

Operators may propose reductions only 

where they can demonstrate that the 

reduced frequency will not significantly 

increase risk. 

(b) An operator must submit its 

proposal to the PHMSA Associate 

Administrator for Pipeline Safety or the 

State agency responsible for oversight of 

the operator’s system. PHMSA, or the 

applicable State oversight agency, may 

accept the proposal, with or without 

conditions and limitations, on a 

showing that the adjusted interval 

provides a satisfactory level of pipeline 

safety. 

§ 192.1019 What must a master meter or 

liquefied petroleum gas (LPG) operator do 

to implement this subpart? 

(a) General. No later than [INSERT 

DATE 18 MONTHS AFTER 

PUBLICATION OF THE FINAL RULE 

IN THE Federal Register] the operator of 

a master meter or a liquefied petroleum 

gas (LPG) gas distribution pipeline must 

develop and fully implement a written 

IM program. The IM program must 

contain, at a minimum, elements in 

paragraphs (a)(1) through (a)(5) of this 

section. The IM program for these 

pipelines should reflect the relative 

simplicity of these types of systems. 

(1) Infrastructure knowledge. The 

operator must demonstrate knowledge 

of the system’s infrastructure, which, to 

the extent known, should include the 

approximate location and material of its 

distribution system. The operator must 

identify additional information needed 

and provide a plan for gaining 

knowledge over time through normal 

activities. 

(2) Identify threats. The operator must 

consider, at minimum, the following 

categories of threats (existing and 

potential): corrosion, natural forces, 

excavation damage, other outside force 

damage, material or weld failure, 

equipment malfunction and 

inappropriate operation. 

(3) Identify and implement measures 

to mitigate risks. The operator must 

determine and implement measures 

designed to reduce the risks from failure 

of its pipeline system. 

(4) Measure performance, monitor 

results, and evaluate effectiveness. The 

operator must develop and monitor 

performance measures on the number of 

leaks eliminated or repaired on its 

pipeline system and their causes. 

(5) Periodic evaluation and 

improvement. The operator must 

determine the appropriate period for 

conducting IM program evaluations 

based on the complexity of its system 

and changes in factors affecting the risk 

of failure. An operator must re-evaluate 

its entire program at least every five 

years. The operator must consider the 

results of the performance monitoring in 

these evaluations. 

(b) Records. The operator must 

maintain, for the useful life of the 

pipeline, the following records: 

(1) A written IM program in 

accordance with this section; 

(2) Documents supporting threat 

identification; and 

(3) Documents showing the location 

and material of all piping and 

appurtenances that are installed after 

the effective date of the operator’s IM 

program and, to the extent known, the 

location and material of all pipe and 

appurtenances that were existing on the 

effective date of the operator’s program. 

Issued in Washington, DC on June 20, 

2008. 

William H. Gute, 

Deputy Associate Administrator for Pipeline 

Safety. 

[FR Doc. 08–1387 Filed 6–20–08; 3:31 pm] 

BILLING CODE 4910–60–P 

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