# U.S. DOT/PHMSA - Report to Congress

**Citation:** 0900006480e836bd  
**Type / status:** rulemaking / current  
**Agency:** Pipeline and Hazardous Materials Safety Administration  
**Effective:** Not stated  
**Published:** Not stated

Assuring the Integrity of Gas Distribution Pipeline Systems A Report to the Congress May 2005 Submitted by: Office of Pipeline Safety Pipeline and Hazardous Materials Safety Administration U.S. Department of Transportation Table of Contents Executive Summary………………………………………………………………………….1 1. Program Overview………………………………………………………………………..2 2. Regulation of Distribution Systems and the Role of State/Federal Governments………..4 3. The Gas Distribution Safety Baseline…………………………………………………….5 Diversity of Operators………………………………………………………………..5...

## Document text

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Assuring the Integrity of Gas Distribution Pipeline Systems
A Report to the Congress
May 2005
Submitted by:
Office of Pipeline Safety
Pipeline and Hazardous Materials Safety Administration
U.S. Department of Transportation

<<<PAGE 2>>>

Table of Contents
Executive Summary………………………………………………………………………….1
1. Program Overview………………………………………………………………………..2
2. Regulation of Distribution Systems and the Role of State/Federal Governments………..4
3. The Gas Distribution Safety Baseline…………………………………………………….5
Diversity of Operators………………………………………………………………..5
Diversity of Infrastructure……………………………………………………………7
Existing Regulations and Practices…………………………………………………..7
Insights from Incident Data…………………………………………………………..9
Innovative Practices…………………………………………………………………11
Monitoring the Effectiveness of Actions……………………………………………11
4. Evaluation of Applicability of Transmission IM Program and Practices………………..12
Integrity Management Elements…………………………………………………….12
Applicability to Distribution Pipeline Systems……………………………………...12
Identifying High Consequence Areas………………………………………..12
a. Hazardous liquid pipelines……………………………….………….12
b. Gas transmission pipelines…………………………………………..13
c. Gas distribution pipelines……………………………………………13
Assessing Pipeline Integrity………………………………………………….14
a. In-line Inspection…………………………………………………….14
b. Pressure testing………………………………………………………14
c. Direct Assessment……………………………………………………15
Applicability of Current IMP Practices………………………………………………17
5. Principles Guiding the PHMSA Approach………………………………………………..17
6. Plan and Schedule for Defining and Implementing Distribution Integrity Management
Requirements…………………………………………………………………………………19
7. Options Being Considered………………………………………………..……………….21
Specific Attention to Excess Flow Valves……………………………………………25
8. Conclusion………………………………………………………………………………...26
Attachments
1. NAPSR State Survey Results -- State Requirements beyond Federal Regulations
Gas Distribution Systems
2. Summary of Allegro Report – Safety Incidents on Natural Gas Distribution Systems:
Understanding the Hazards, April 2005
3. NARUC Resolution on Distribution Integrity Management, February 16, 2005
4. Position of the American Public Gas Association on Distribution Integrity Management
5. PHMSA/OPS Phase 1 Action Plan
List of Figures
1. Distribution systems subject to 49 CFR 192………………………………………………..6
2. Relationship among Federal Requirements, Standards or Guidelines, and State
Requirements…………………………………………………………………………………23
3. Example of High-level Federal Performance Requirements……………………………...24
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Acronyms
AGA – American Gas Association
AGF – American Gas Foundation
APGA – American Public Gas Association
CFR – Code of Federal Regulations
DA – Direct Assessment
DOT – Department of Transportation
EIA – Energy Information Administration
EFV – Excess Flow Valve
FR – Federal Register
ILI – In-line inspection
IM – Integrity Management
IMP – Integrity Management Plan
LP – Liquid propane
NAPSR – National Association of Pipeline Safety Representatives
NARUC – National Association of Regulatory Utility Commissioners
OPS – Office of Pipeline Safety
PHMSA – Pipeline and Hazardous Materials Safety Administration
USC – United States Code
ii

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A Report to the Congress: Assuring the Integrity of Gas 1
Distribution Pipeline Systems
Executive Summary
The FY 2005 Conference Committee on Appropriations asked1 the Department of
Transportation’s (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA)
Office of Pipeline Safety (OPS) to submit a report detailing the extent to which integrity
management plan elements may be applied to gas distribution pipeline systems to enhance
safety. “Integrity management” refers to programs that OPS has required of hazardous liquid
and gas transmission pipeline operators, through rules promulgated within the last five years.
Integrity management requirements have not yet been established for gas distribution pipeline
systems. The Department of Transportation’s (DOT) Inspector General recommended that
OPS take this action in testimony before the Congress in 2004.2
The principal focus of the existing integrity management regulations for pipelines is to
identify the portions of the pipeline system that pose the most risk; to inspect the physical
condition of those portions of the pipelines; and to repair any defects that could challenge the
pipeline integrity. The fundamental principles of integrity management require:
understanding the infrastructure and the risks it poses, and then taking actions to address those
risks. There are significant differences in the design of gas distribution pipeline systems
compared to the pipelines subject to current integrity management regulations. These include
pipe size, operating pressure, materials, and the large number of branches and connections in
distribution systems. These design differences significantly limit the applicability of the
inspection techniques currently in use for those pipelines to distribution pipeline systems.
The challenge is to develop appropriate methods to apply the principles of integrity
management to enhance the safety of distribution pipeline systems, while remaining mindful
of costs and service disruptions and their potential impact on consumers.
Gas distribution pipelines, those that deliver gas directly to consumers, are almost entirely
under the regulatory oversight of state agencies. OPS has implemented a program jointly with
its state partners and a broad range of stakeholders, to identify means appropriate to
distribution pipelines to focus attention on areas that pose the highest risk and to better assure
the integrity of those portions of the distribution systems, in other words, integrity
management.
The first phase of the program is to be completed in 2005 and will identify the nature of
requirements that might be imposed and any additional guidance or consensus standards that
might be needed to assist operators in implementing any integrity management requirements.
This phase will include consideration of a multi-faceted set of potential approaches, including
regulations and guidance, but will also consider a national education program, development of
new inspection technologies, and legislative models that states could adopt. The second
phase, to begin in January 2006, will include development of appropriate requirements by
OPS and preparation of guidance/standards by appropriate bodies.
1 House of Representatives Report 108-792, November 20, 2004.
2 “Progress and Challenges in Improving Pipeline Safety,” Statement of the Honorable Kenneth M. Mead,
Inspector General, Department of Transportation, before the Committee on Energy and Commerce,
Subcommittee on Energy and Air Quality, U. S. House of Representatives, July 20, 2004.

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A Report to the Congress: Assuring the Integrity of Gas 2
Distribution Pipeline Systems
1. Program Overview
The DOT Inspector General, in testimony before Congress in July 2004,3 recommended that
OPS 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. The Appropriations Committee asked OPS “to report to the House
and Senate Committees on Appropriations by May 1, 2005, detailing the extent to which
integrity management plan [IMP] elements may be applied to the natural gas distribution
pipeline industry in order to enhance distribution system safety”.4
Industry and government have long been committed to the safe operation of the Nation’s 1.9
million miles of natural gas distribution pipelines. Building on the existing set of
requirements, regulators and pipeline operators continue to examine natural gas distribution
practices to understand the most effective approaches to improving the integrity and safety of
these systems.
During the past five years, OPS (as part of PHMSA) has promulgated regulations designed to
improve the integrity of liquid and gas transmission pipelines. Together with our State
partners, PHMSA has undertaken inspection of the programs by which operators are
implementing these regulations. Implementation of these regulations has led both to
improvements in the operators’ knowledge of their pipelines, and to identification and repair
of thousands of defects in these pipelines. OPS also regulates distribution pipeline systems.5
Pursuant to agreements among OPS and the States, state inspectors perform most of the
inspection and enforcement of the pipeline safety regulations on gas distribution systems.
OPS ensures that State programs provide safety oversight in compliance with the Federal
pipeline safety regulations.
OPS and our State partners developed a program through which we will thoroughly
reexamine means for strengthening the safety of distribution pipeline systems. This program
will address the three elements of the strategy described by the DOT Inspector General: (a)
understanding the infrastructure; (b) identifying and characterizing the threats; and (c)
determining how best to manage the known risks (prevention, detection and mitigation).
These three elements are essentially the same as those underlying the transmission pipeline
integrity management regulations. The program will provide the basis for establishing
integrity management requirements for distribution pipeline systems. These requirements
must be different than those that have been applied to hazardous liquid and gas transmission
3 Ibid.
4 House of Representatives Report 108-792, November 20, 2004.
5 Gas transmission pipelines transport gas from areas where it is produced to areas where it is consumed. These
pipelines are generally steel, of large diameter, operate at high pressures, and traverse long distances, sometimes
more than 1,000 miles. Distribution pipeline systems are the network of pipes in communities that provide gas
directly to consumers. They consist of small diameter pipelines, operating at low pressure, and constructed of a
variety of materials. Distribution pipelines exist as a network with many branches in short distances (e.g., a
service line connection for each house on a city street). The differences between the two types of pipelines can
lead to a need to use different approaches to assuring safety, as described in this report.

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A Report to the Congress: Assuring the Integrity of Gas 3
Distribution Pipeline Systems
pipelines, because the models and tools prescribed by those regulations have only very limited
applicability to distribution pipeline systems.
The program presented in this Report was designed to identify opportunities for improving the
safety of distribution pipeline systems. Our analysis of the past few years of data identified
that in order to address safety threats to distribution pipelines, there are a number of target
audiences that PHMSA needs to involve in developing strategies to reduce these threats.
Accordingly, OPS is involving a larger number of key stakeholder groups than contacted in
the past, including State and Federal regulators, representatives from the spectrum of
distribution operators, interested members of the public, and representatives of our Nation’s
fire service. These participants are organized into work/study groups that will gather and
analyze data to help focus the effort and ultimately identify options for attaining improved
safety. In addition, OPS will be posting information on a public web site as the program
activities progress, to offer an opportunity for other interested members of the public to
comment.
OPS organized the program in two major phases. During the remainder of 2005 (Phase 1)
work/study groups will gather and analyze data, and develop the elements of a safety
improvement program. During the following year (Phase 2) OPS and pipeline standards
development organizations (if needed) will work to develop requirements, guidelines and
standards that will be implemented using some combination of four options favored by a
consensus of the stakeholder group.
• The first option is a high level, risk-based, performance-oriented Federal regulation.
• The second option is supplemental information through one or more guidelines or
national consensus standards describing choices on how the spectrum of distribution
pipeline operators might apply fundamental risk-based principles to achieve the
desired improvements. States would then have the opportunity to draw on the
standards and guidance to promulgate regulations describing how the unique set of
operators they regulate should implement improvements satisfying the Federal
requirements.
• Third is a structured nation-wide education program on preventing excavation
damage, focused on the new 811 one-call program.
• The final option is development of innovative safety technologies capable of
producing observable safety improvements.
The requirements that may result from this program could prove expensive for operators to
implement. The view of an executive steering group6 was that it is important to consider all
costs related to new efforts to prevent and mitigate distribution line incidents together, in
order to assure the most cost-effective solution. Thus, the group emphasized the importance
of evaluating all options for preventing, detecting and mitigating threats to public safety
consistently. For example, the group indicated its preference that use of excess flow valves
(EFVs) as a means of mitigating the impact of severed gas distribution lines should be
6 See Section 6 for a description of the groups involved in the Action Plan

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A Report to the Congress: Assuring the Integrity of Gas 4
Distribution Pipeline Systems
considered as part of the overall distribution safety improvement program, rather than being
addressed in a separate Federal mandate.
2. Regulation of Distribution Systems and the Role of State/Federal Governments
The principal authority for regulating the safety of gas distribution pipeline systems is
exercised by State governments. Under 49 USC 60105 and 60106, States may exercise
jurisdiction if their pipeline safety programs are certified by the DOT or if they enter into an
agreement with DOT absent certification. At this time, all States except Alaska and Hawaii
exercise safety jurisdiction under these provisions. States 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. Finally, they can provide incentives for safety improvements, often through their
rate-setting authority.
The Federal government has ultimate responsibility in regulating intrastate distribution
pipeline operators. The Federal standards in 49 CFR Part 192 establish a minimum set of
safety requirements that all states must implement. The DOT also collects data concerning
distribution system mileage, incidents that occur on systems, their leak repair experience and
other information about the size, age and material(s) of construction of their distribution
piping. Initial consideration of an approach to integrity management for distribution pipeline
systems will seek to identify changes that could be made in DOT data collection that would
help improve the ability of State and Federal regulators to analyze and more clearly
understand distribution system’s operating experience. The Office of Pipeline Safety will
define further what improvements are needed and will determine if changes to its data
collection forms are needed.
OPS provides funding for the operation of State pipeline safety programs through a grant
program that funds States’ oversight efforts. OPS has, in the past, identified emphasis areas
for State focus in their oversight programs. These emphasis areas have included content of
state regulations, pursuit of special initiatives, approaches to inspection of operators, and data
collection and reporting. OPS can adjust its criteria for state funding grants to assure that
appropriate emphasis exists in each State’s program.
One area for special grant allocation resources is damage prevention – being proactive to
reduce the likelihood that distribution pipelines will be damaged during excavation work.
(This is a principal threat to the integrity of distribution pipelines).
OPS is also engaged in work with state fire marshals, and has included a representative of this
community in the distribution integrity management program. Representatives of public
interest groups are also involved in helping to define the appropriate approaches to assuring
distribution system integrity. This inclusiveness demonstrates the willingness of OPS and
States to go beyond previous efforts to improve the assurance of distribution pipeline system
safety. The OPS will also seek other input through posting documents related to this program
on a web site.

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A Report to the Congress: Assuring the Integrity of Gas 5
Distribution Pipeline Systems
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 assure that the
particular needs of their citizenry are fulfilled. They also need to assure that the safety
standards being applied are appropriate for the unique environment in which gas distribution
occurs. Distribution pipeline systems are limited in geographic scope. 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 gas producing regions also can be important, as natural gas that is distributed near
production areas may be subject to little processing and may contain more contaminants, with
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 requirements intended to address frost
heave damage in the desert southwest. Integrity management requirements for distribution
pipeline systems will be structured in a manner that allows States the necessary flexibility in
implementation.
3. The Gas Distribution Safety Baseline
In order to know what opportunities there are to enhance distribution pipeline safety, we must
first examine where and how operators are performing today.
There is very significant diversity among gas distribution pipeline operators in the United
States. The size and technical depth of operators of distribution pipeline systems, the nature
of the systems they operate, the requirements they must meet, and the practices that they use
to assure safety all vary widely. An understanding of these differences, and the current
approach to sharing and using practices that go beyond the regulations, i.e., the “baseline”
level of program management, will be useful in understanding the approach being taken to
enhance distribution integrity management.
Diversity of Operators
Operators of distribution pipeline systems subject to OPS/State safety regulation are of four
different types:
• Master meter systems (e.g., trailer parks, individual multi-occupancy buildings)
• Publicly owned (e.g., town/city/county) municipal utilities
• Investor-owned utilities
• Propane gas distribution systems
The order within this list represents the prevalence of each type of operator. There are
approximately 1,000 publicly owned utilities delivering gas to consumers in the United States.
By contrast, there are approximately 250 investor-owned utilities engaged in this business.

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A Report to the Congress: Assuring the Integrity of Gas 6
Distribution Pipeline Systems
There are several thousand master meter operators and a few hundred liquid propane (LP) gas
systems that are subject to the safety regulations in 49 CFR Part 192.
Figure 1 - Distribution systems subject to 49 CFR 192
(Prepared by APGA from E IA data)
# of systems
500
450
400
350
300
250
200
150
100
50
0
438
354
Municipal
Investor-owned
96
59 69
50
35
20
6 0
10
< 100 100-1000 1000-10000 10000-100000 100000-1 million > 1 million
# of customers (from EIA Form 176)
Note: EIA does not maintain data on the number of customers served by master meter systems or liquid propane
(LP) gas systems. There are several thousand master meter operators, the vast majority of which serve less than
100 customers. There are approximately 200 LP gas systems most of which also serve less than 100 customers.
Within each of these groups, the size of individual operators also varies widely, as shown in
Figure 1. Publicly-owned utilities tend to be smaller, with a majority serving less than 1,000
customers. In general, investor-owned utilities tend to be larger, with slightly over 100
companies serving more than 100,000 customers each. There are examples, though, of
publicly owned utilities serving 100,000 customers and of investor-owned companies serving
less than 1,000. The variability makes it difficult to generalize regarding these groups. The
particular circumstances of each operator must be taken into account.
Master meter operators are businesses such as apartment complexes, or mobile home or trailer
parks, or are government entities like housing authorities and universities that receive gas
from an outside supplier and distribute it via pipelines located within their facilities. These
operators are generally small, with a large majority serving fewer than 100 customers.
Distribution of gas, or operation of the distribution systems, is not their principal business.
Propane system operators subject to pipeline regulation are also small. Propane used in
individual installations, such as a rural farm with its own propane tank, is not subject to
regulation as a pipeline system. Propane systems become subject to regulation when they
distribute gas, by pipeline, to 10 or more customers. The large majority of these systems
likely serve fewer than 100 customers.

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A Report to the Congress: Assuring the Integrity of Gas 7
Distribution Pipeline Systems
Diversity of Infrastructure
The pipeline systems operated by these operators are also subject to much variation.
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 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) technology.
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.
Additional diversity will likely be introduced as systems age, new customers are added, and
portions of the original systems are replaced.
Individual master meter systems and propane systems tend to be relatively uniform due to
their small size and limited geographical extent.
Existing Regulations and Practices
The Federal pipeline safety standards in 49 CFR Part 192 provide a common base of
requirements applicable to distribution pipeline systems. These standards address design,
construction and operation of pipeline systems as well as requirements affecting inspection,
maintenance, repair and testing and also qualification of pipeline operations personnel. States
are required to adopt these standards as one of the criteria for certifying their pipeline safety
programs or for entering into an agreement with OPS to exercise safety jurisdiction. States
can, and do, impose additional requirements where appropriate.
The National Association of Pipeline Safety Representatives (NAPSR) is an organization
consisting of the senior regulatory program manager from each State that exercises pipeline
safety jurisdiction. NAPSR recently conducted a survey of its members to identify the extent
of additional State requirements that go beyond Part 192. The survey identified that most
States impose some additional requirements. A majority impose stricter criteria for reporting
incidents and/or requires that operators notify the regulator of construction or testing that
would provide an opportunity for the regulator to examine the pipeline and observe safety-
significant work. These type of requirements reflect the close oversight relationship that
exists between most state regulatory programs and the operators they regulate. State
regulators generally interact routinely with operators under their jurisdiction, and therefore
know their systems and personnel. States are actively engaged, on a daily basis, in overseeing
safe operations. Additionally, approximately 25 percent of the States impose requirements for
leak surveys beyond those required in Part 192.

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A Report to the Congress: Assuring the Integrity of Gas 8
Distribution Pipeline Systems
The NAPSR survey also identified that approximately 65 percent of States have a program to
replace some types of distribution piping. This may include cast iron pipe, uncoated and
unprotected steel pipe, or certain types of plastic pipe that have been found to be subject to
deterioration in service. The replacement programs vary in scope. In some cases, they
involve all (or nearly all) of the operators in a State. In other cases, they may involve
individual operators and may have been initiated as a result of an incident or event that
highlighted problems associated with the aging material.
A summary of the NAPSR survey results is included as Attachment 1 to this report.
In addition to the NAPSR survey, OPS contacted several larger investor-owned utilities to
obtain information about their safety practices that exceed minimum regulatory requirements.
The operators surveyed, all of which serve mid- to large-sized cities, all reported that they use
risk evaluation to help direct work on their pipelines. This supports a conclusion of the
American Gas Foundation (AGF) that 82% of companies they surveyed use risk control
practices.7 Use of risk models is not currently required of distribution system operators.
Neither OPS nor States have audited these models or their application. We therefore cannot
comment yet on the thoroughness of the approaches used, but note with satisfaction that the
concept of using an estimate of risk to manage safety activities is becoming widely prevalent.
OPS’ discussions also identified that the larger operators all had pipe management programs
that included replacing portions of their system: where problems had been experienced
identifying materials susceptible to failure; where certain construction practices potentially
leading to problems may have been used; that include their older pipelines; or based on
estimated risk. Again, this reinforces the AGF conclusion that 65% of surveyed companies
had replacement programs.8 (It should be noted that replacement of pipe in highly built-up
urban areas can be difficult due to the number and complexity of buried infrastructure
facilities and the difficulty of working in the urban environment.)
The operators contacted by OPS also perform leak surveys more frequently, based on unique
operating conditions, than would be required by regulations and implement special practices
to reduce third party damage.
Most of the operators contacted by OPS also reported that they have elected to install excess
flow valves (EFV) for new and replacement services, which goes beyond the regulatory
requirement that customers be apprised of the availability of EFVs and that they be installed if
the customer agrees to pay for them.
The most prevalent safety practice followed by distribution system operators that is not
required by Part 192 is membership in damage prevention programs, most often referred to as
“one-call” programs. The AGF reports that over 95 percent of operators belong to such
7 American Gas Foundation, “Safety Performance and Integrity of the Natural Gas Distribution Infrastructure”,
January 2005, p. 5-11.
8 Ibid, p. 5-13.

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A Report to the Congress: Assuring the Integrity of Gas 9
Distribution Pipeline Systems
programs.9 Most states require gas utilities to belong to one-call programs. The breadth of
participation in these activities provides a basis to presume that excavation damage incidents
can be reduced. However, unfortunately, these incidents continue to occur. They are
undoubtedly less prevalent than they would be in the absence of one-call programs, but they
still represent a threat to distribution pipeline systems. This program will specifically include
a review of industry practices and other approaches to prevent or reduce damage to identify
ways in which their effectiveness can be improved.
Insights from Incident Data
The principal source of information available about distribution pipeline system safety and
integrity is the data resulting from incident reports submitted to OPS. These reports are filed
by operators, pursuant to 49 CFR 191.9, and include events occurring on jurisdictional
pipelines that involve either: 1) a death or personal injury necessitating in-patient
hospitalization; 2) estimated property damage, including cost of gas lost, of the operator or
others, or both, of $50,000 or more; or 3) events that are significant, in the judgment of the
operator, even if neither of the other criteria is met or exceeded.
OPS changed its incident report form in 2004 to require that the cause of incidents be reported
more precisely. All incidents reported prior to that time were attributed by the reporting
operator to one of five major causes, one of which was “other.” Using the revised forms,
operators identify one of seven major causes, which are further subdivided into 25 second-
level causes. This change is intended to improve our understanding of the factors that result
in gas pipeline incidents.
The set of incident data submitted by operators represents significant problems that occur on
the pipeline. It does not include all events involving or exacerbated by natural gas from
distribution pipeline systems. For example, problems with an appliance in a customer’s home
could result in an accumulation of gas, an explosion, and fire, potentially resulting in injury or
death. Although the media may report such events as gas pipeline incidents, they are not.
OPS has no regulatory authority over customer-owned piping or gas appliances, and operators
are not required to report such events to OPS. Customer piping within homes and businesses
is regulated by local building codes, often based on the National Fuel Gas Code or other
model codes.
There have been two recent studies that considered recent distribution incident experience.
One was conducted by the AGF, under the oversight of a committee formed of representatives
from AGF members and state pipeline safety regulators. The results of this study were
reported in “Safety Performance and Integrity of the Natural Gas Distribution Infrastructure,”
published by AGF in January 2005. The other was performed by Allegro Energy Consulting,
in late 2004, under contract to OPS.
The AGF study covered the period from 1990 to 2002. During that period, AGF found a
statistically significant downward trend in “serious” incidents, defined as those involving a
9 Ibid, p. 5-12.

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A Report to the Congress: Assuring the Integrity of Gas Distribution Pipeline Systems
10
death or injury. (AGF chose to focus on these incidents because the reporting criteria are not
as subjective as “significant to the operator” nor do local economic factors or inflation affect
reporting of an event wherever or whenever it occurs.) The AGF concluded there were
approximately 1.6 serious incidents per 100,000 miles of distribution pipeline during 2002.
The AGF study identified that nearly half of the serious incidents occurring during the study
period were a result of outside force damage. The only other cause category contributing to
more than 10 percent of serious incidents was “other” which was responsible for almost 27
percent.
The Allegro study re-evaluated five years of incident report data (1999-2003) to re-classify
them to the new cause categories. This was accomplished by reviewing the narrative
description of the incident that the operator provided when submitting the original report.
Allegro considered 634 incidents reported in the five-year period. One third of them involved
death or injury, i.e., would have been considered “serious” incidents by the AGF study.
Nearly one half were reported due to the cost of damages alone. Six percent of the incidents
apparently did not meet any of the reporting criteria, but they were still retained in the Allegro
analysis.
Allegro’s re-classification was successful in reducing the number of incidents for which the
cause could not be attributed from the 27 percent noted in the AGF study to 12 percent.
Allegro further found that a large majority of the incidents (67%) were caused by outside
force damage. The new cause categories permitted Allegro to break the outside force damage
category down into several components. Thirty-eight percent of the incidents were caused by
excavation and mechanical damage (the vast majority caused by third parties), but 29 percent
were caused by other sources of outside force. This new category included two major
components: “fire first” and vehicle damage, each representing 11 percent of the total number
of incidents.
The fire first events represent incidents in which a building was on fire and the operator
responded, but the fire was not caused by a gas leak. In many cases, the gas supply system in
the building is compromised or damaged by the fire and contributes to its intensity until the
gas can be shut off. Fire first incidents are not caused by problems in the gas distribution
system and cannot be addressed in a distribution integrity management program.
The vehicle-related events represent incidents in which a vehicle impacts a portion of the
pipeline system, often the above-ground meter assembly. The accidents resulted from
multiple causes, including drivers operating their vehicles while intoxicated and unattended
vehicles rolling into the pipeline system. Allegro found that this category of incidents, while
representing 11 percent of all incidents, involved 25 percent of the fatal incidents over the
period studied. Thus, these data tell us that 1 out of 4 of the fatal incidents during this period
could not have been prevented by any preventive action taken on the pipeline. Reducing the
number of these incidents is likely to require actions that affect persons not under the
regulatory jurisdiction of OPS or State pipeline regulatory authorities, i.e., vehicle operators.
A summary of the Allegro report is included as Attachment 2.

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A Report to the Congress: Assuring the Integrity of Gas Distribution Pipeline Systems
11
Innovative Practices
The American Gas Association (AGA) each year sponsors groups from among its members to
identify innovative practices that they employ to improve operational performance and safety.
These groups typically evaluate approximately five topic areas (e.g., damage prevention, main
and service replacement, system reliability). In each area, practices of member companies are
shared, innovative practices are identified, and the information is exchanged with participants
at a roundtable forum. Detailed information is available only to companies that have
participated in the groups.
These forums serve a useful purpose and can contribute to expanding the understanding and
application of innovative practices. This expansion can occur among participants, which are
generally the larger, investor-owned companies. The results of these efforts are not available
to operators that do not directly participate in the program, particularly publicly-owned
operators that are not usually members of AGA.
OPS believes that these activities have a positive impact on the reduction of incidents
disproportionate to the percentage of operators that participate. There are two reasons for
believing this: the large-operator participants operate a much larger percentage of the total
distribution pipeline mileage than their numbers might suggest; and smaller operators,
particularly those with only a few persons on staff and a limited amount of pipeline mileage,
generally have much better detailed knowledge of their systems and the issues that affect
them.
Nevertheless, the impact of these activities is limited. Participation is not available to
municipal operators who are not AGA members and often lack the staff resources necessary
to become involved in this kind of outside activity. Also, not all AGA members participate in
these activities.
Monitoring the Effectiveness of Actions
It is important that the effectiveness of whatever actions are taken to improve distribution
pipeline safety be monitored. 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.
Other interim measures are needed to evaluate the effectiveness of any new integrity
management requirements implemented for distribution pipeline systems. An interim
measure might be how any new regulatory initiatives impact system operators (e.g., the
number of assessments or repairs that have been conducted is an interim measure of the
effectiveness of the hazardous liquid and gas transmission integrity management rules). The
program described in this report includes development of a way to measure these impacts and
to develop a baseline from which improvements can be measured.

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A Report to the Congress: Assuring the Integrity of Gas Distribution Pipeline Systems
12
4. Evaluation of Applicability of Transmission IM Program and Practices
OPS promulgated regulations in recent years requiring that pipeline operators (other than
distribution pipeline operators) implement integrity management programs. These regulations
apply to operators of hazardous liquid pipelines (49 CFR 195.452, published at 65 FR 75378
and 67 FR 2136) and to operators of gas transmission pipelines (49 CFR 192, Subpart O,
published at 68 FR 69778). It is reasonable to ask why the same techniques used in these
regulations cannot simply be applied to gas distribution pipeline systems. Both regulations
set requirements for making best use of information to set safety priorities and to perform
continuous evaluations.
Integrity Management Elements
The integrity management regulations for hazardous liquid and gas transmission pipelines are
similar. Both require that operators identify segments of their pipeline where an incident
could create high consequences. Both require that operators implement a program to assure
the integrity of these pipeline segments. An operator’s integrity management program must
include an assessment of the risk posed by the pipeline and use of that risk information to
prioritize certain actions. Principal among these actions is the conduct of inspections/
assessments utilizing in-line inspection tools, pressure testing, direct assessment, or other
technology that provides an equivalent understanding of the pipe condition. Anomalous
conditions identified by the inspections must be repaired within a period commensurate with
the safety significance of the anomaly.
Applicability to Distribution Pipeline Systems
The basic premise of the integrity management programs for gas transmission and hazardous
liquid pipelines – identify the risks and take actions to address them – is obviously applicable
to distribution pipeline systems. However, many of the techniques used to implement this
premise for hazardous liquid and gas transmission pipelines are of more limited applicability
to distribution systems.
Identifying High Consequence Areas
The first element of existing integrity management programs is to identify those segments of
the pipeline where an incident/break could result in high consequences. This is important for
hazardous liquid and gas transmission pipelines because both traverse large distances,
including areas that are sparsely populated or where accident consequences would be small.
So-called high consequence areas are identified in order to improve the effectiveness of
integrity management requirements by focusing efforts on the pipe where significant
consequences could occur.
a. Hazardous liquid pipelines
Hazardous liquids generally do not evaporate if released during a pipe break. Released
liquids can spread to adjacent areas and cause adverse consequences to people, local flora and

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A Report to the Congress: Assuring the Integrity of Gas Distribution Pipeline Systems
13
fauna, or drinking water supplies. OPS, working with State heritage and resource
conservation programs, has identified areas in the U.S. that include population concentrations,
habitats for threatened and endangered species, and sources of drinking water. Hazardous
liquid pipeline operators are required to compare these locations to the location of their
pipelines, identify where accidental releases from their pipelines could affect these areas, and
focus their integrity management efforts on those pipeline segments. This approach is not
applicable to natural gas pipelines, since natural gas is lighter than air and will disperse into
the atmosphere rather than flow overland to nearby areas.
b. Gas transmission pipelines
The risk from gas pipeline releases is ignition of the gas and the resulting fire or combustion
occurring near the location of the pipeline. For gas transmission pipelines, pipeline segments
that could cause significant consequences are identified using a mathematical correlation
based on past incidents that estimates the distance from the pipeline that could be affected by
a resulting fire occurring from the ignition of the released gas along the pipeline. Operators of
natural gas transmission pipelines are required to evaluate “potential impact circles” based on
this calculated distance to determine whether the circles encompass a threshold number of
residences, locations where people congregate, or locations where there are populations that
would be difficult to evacuate. Gas transmission pipeline integrity management activities are
focused on these pipeline segments.
c. Gas distribution pipelines
Gas distribution pipeline systems are different. They do not traverse long distances, including
many areas of limited population. They exist almost entirely in populated areas, because their
purpose is to provide gas service to the residences and businesses of those populations.
Unlike the case of transmission pipelines, identifying areas where the 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.
Further, the mathematical correlation used to estimate the area that could be affected by an
incident on a gas transmission pipeline is not applicable to most distribution pipelines. It
presumes that pipe failure and the potentially resulting fire will occur at the location of the
pipeline leak/failures. This is a reasonable assumption for high-pressure transmission
pipelines, where the internal pressures create stresses that expand small leaks into ruptures.
The assumption is inappropriate for distribution systems, since they do not operate at high
pressures. Leaks from low-pressure distribution pipelines do not usually progress to failures.
Instead, gas that is released from the pipeline migrates underground. The released gas can
collect in confined spaces, such as nearby buildings, and result in fires that occur at locations
away from the pipeline.
The techniques used to identify hazardous liquid and gas transmission pipeline segments
where incidents can result in high consequences are not applicable to gas distribution pipeline
systems. Some other means of focusing integrity management attention is needed.

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Assessing Pipeline Integrity
The techniques used to conduct inspections/assessments of hazardous liquid and gas
transmission pipelines have limited usefulness for gas distribution pipeline systems. These
techniques are:
• In-line inspection
• Pressure testing
• Direct Assessment
a. In-line Inspection
In-line inspection (ILI) is conducted by passing a tool through the pipeline that examines the
pipe wall to identify areas where the wall has been damaged or where wall thickness has been
reduced, such as by corrosion. The tools used must be of a size that will fit in the pipeline.
The tools fit tightly and are pushed along by the pressure of the moving gas or liquid in the
pipeline. The sensors used to examine the pipe wall almost always make use of a magnetic
flux imposed on the pipe wall, and thus only work with ferrous metal pipelines.
The vast majority of pipelines in distribution pipeline systems are of small diameter, some
less than one inch in diameter. ILI tools cannot be made that will fit these small-diameter
pipelines using currently available technology. The gas pressure in distribution pipeline
systems is also generally too low to propel a tool, even if current technology provided one to
fit in the line. In addition, a large portion (as much as half) of the pipe in distribution pipeline
systems is plastic. The sensors used in in-line inspection tools cannot examine plastic pipe
walls. Finally, distribution pipeline systems exist as a network of interconnected pipe rather
than as single runs of pipe traversing long distances. It is not practical for in-line inspection
tools to negotiate the many turns and interconnections that exist in distribution pipeline
networks.
ILI tools have limited utility in assuring distribution pipeline integrity.
b. Pressure testing
Pressure testing is a traditional means of testing a pipeline. The ends of a section of pipe to be
tested are closed, using valves or temporary plugs, and the fluid (water or gas) between those
ends is raised in pressure until it produces stresses in the pipe wall that are near those that the
pipe was designed to withstand. These pressures are much higher than those experienced
during normal operation. Weak areas, such as result from corrosion that reduces pipe wall
thickness, are identified by leaks or ruptures during this pressure test. Such areas are found
and repaired, and the test is repeated until the pipe is demonstrated to be able to hold the high
pressure. This assures a significant safety margin for subsequent operation at the lower
pressures normally experienced in operation.

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15
All pipes can be tested using pressure tests. Virtually all pipes are initially subjected to
pressure tests at the mills where the pipe is produced to verify the adequacy of the
manufacturing process. Distribution pipelines are also pressure tested prior to being placed
into service, as required by 49 CFR 192, Subpart J. However, use of pressure testing on
installed pipeline systems can pose significant difficulties.
Pipe to be pressure tested must be taken out of service. The act of plugging the ends to
contain the high test pressure precludes using the pipe at the same time to transport gas. Use
of pressure testing in gas distribution pipeline systems thus would require that gas service to
customers be interrupted for the duration of the test. Each affected customer would have to be
visited to assure that valves controlling gas flow to pilot lights are closed, so that gas would
not enter the structure when service is resumed and potentially result in an ignition. Each
affected customer must again be visited once gas flow is resumed to re-open those valves and
re-light pilot lights. This process is time consuming and costly. Errors in carrying out this
process could result in the very consequence (i.e., ignition and a fire) that integrity
management programs are intended to prevent.
Additional difficulties are introduced by the interconnected network nature of gas distribution
pipeline systems. Pressure testing a single length of pipe requires that the two ends be closed.
Where interconnections and branches occur frequently (e.g., every block in most city
systems), it is not practical to test the segments between each branch point individually.
Thus, each branching pipe must be closed, increasing the number of excavations that must be
made and the complexity of conducting the test. Additionally, each service connection off of
a gas main must be plugged to permit pressure testing of the main. Pressure testing of service
lines requires that they be plugged at the point at which they enter the customer’s location,
requiring disturbance of the customer’s property or work within their home/business.
Pressure testing of distribution pipeline systems, while possible, is extremely costly and
impractical.
c. Direct Assessment
As use of in-line inspection devices can also be impractical for some gas transmission
pipelines, an alternative method of assessment, called Direct Assessment, was developed. In-
line inspection of gas transmission pipeline can be impractical because of changes in pipe
diameter or valves that obstruct the passage of the ILI test device. Additionally, it is also
impractical to remove some transmission pipelines from service for pressure testing (e.g., a
pipeline that is the sole source of gas supply for a community). Direct Assessment was
developed as an assessment method for transmission pipelines that cannot be tested by these
other methods. Direct Assessment does not require service interruption. It uses indirect
inspection methods to identify locations where corrosion could be occurring on the pipeline.
These locations are then excavated, examined, and repaired as needed.
Direct Assessment is a new technique that has been validated for transmission pipelines. The
formal and comprehensive process associated with Direct Assessment has not been

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A Report to the Congress: Assuring the Integrity of Gas Distribution Pipeline Systems
16
demonstrated to be effective for distribution pipeline systems and there are technical reasons
to believe that it will not be effective in that environment.
The indirect inspection techniques that are used as part of Direct Assessment for determining
where excavation and direct examination are needed involve looking for inconsistencies in the
electrical current imposed on steel pipelines to prevent corrosion (cathodic protection). These
techniques are not applicable for plastic pipe, and there is no practical method for conducting
an indirect examination of plastic pipe. Since approximately half of piping in distribution
pipeline systems is plastic, Direct Assessment can simply not be used on approximately half
of distribution network piping.
Even for metal pipe, application of Direct Assessment in a distribution network environment
will be, at best, problematic. The distribution pipelines posing the highest risk tend to be
older systems that are cast iron, bare steel (i.e., not coated to protect against corrosion), and
coated steel pipe not subject to cathodic protection. The indirect inspection methods used as
part of Direct Assessment have very limited applicability for these types of pipe. The
methods usually rely on detecting minor variations in the cathodic protection current that
could indicate breaks in the pipe coating where corrosion could be occurring. These areas are
then excavated so that the pipe can be examined directly to determine if corrosion is present.
The indirect methods cannot identify specific areas where there is a higher likelihood of
corrosion if the entire pipe surface is uncoated or if there is no impressed cathodic current in
which to look for variations. Again, the indirect inspection methods do not work or are very
difficult to apply for these situations.
Coated steel pipe that is cathodically protected is the ideal environment for use of Direct
Assessment on transmission pipelines. Its use for similar pipe in distribution pipeline systems
is not as straightforward. Distribution pipelines are installed in urban environments in which
they share space with other underground utilities including water pipes, cable TV, fiber optic,
telephone, and electric service. These other underground services can result in significant
electrical interference that could make it difficult or impossible to evaluate small changes in
the electrical current imposed on cathodically-protected pipelines to identify breaks in pipe
coating, etc. That is precisely the purpose of the indirect examinations, as breaks in coatings
are areas where corrosion could occur and direct examination may be appropriate. Further
research would be required to estimate with certainty the percentage of distribution pipeline
where Direct Assessment, as defined for transmission pipelines, may prove practical, but it is
likely to be small.
Direct Assessment, then, cannot be used on approximately half of distribution pipelines (i.e.,
plastic pipe). It is of limited, if any, value for the riskiest distribution pipe (i.e., cast iron, bare
steel, and non-cathodically-protected steel). It may have, at best, limited applicability for the
pipe that is best protected and likely of least risk (i.e., coated cathodically-protected steel
pipe).

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17
Applicability of Current IMP Practices
As discussed above, the traditional techniques used as part of integrity management programs
for hazardous liquid and gas transmission pipelines are not appropriate for use with
distribution pipeline systems. The methods used to identify pipeline segments where high
consequences can occur do not accommodate the different nature of incidents on distribution
pipeline systems. The means used to inspect the condition of the pipelines are often
impractical (in-line inspection), costly and impractical (pressure testing), or of questionable
and likely little value (Direct Assessment).
Additional work, through this program, is needed to identify practical ways to address
integrity management questions for distribution pipeline systems, including how to identify
pipe that requires additional attention and the appropriate actions to apply to that pipe.
5. Principles Guiding the PHMSA Approach
If the tools and methods used for integrity management of other pipeline systems cannot
simply be applied to distribution pipeline systems, then it is necessary to identify new
approaches using a set of basic guiding principles. Stakeholder groups have also recognized
this need and have taken actions that inform our principles.
The National Association of Regulatory Utility Commissioners (NARUC) is an organization
whose members include the governmental agencies that are engaged in the regulation of
utilities in each State. NARUC considered the issue of assuring the integrity of distribution
pipeline systems at its winter meeting, held in Washington, DC in February 2005. NARUC
adopted a resolution at that meeting supporting the joint efforts of OPS, gas distribution
pipeline operators and other stakeholders to develop an approach to better assure distribution
pipeline integrity. NARUC recognized the effort already invested in this area and the
difficulties involved, as summarized above. NARUC recommended that an approach be
developed,
that uses risk-based, technically sound and cost-effective measures, which reflect that
stakeholders are: knowledgeable of the infrastructure; can identify threats against their
systems; and can take appropriate measures to reduce the risk of system failures while
balancing the needs to ensure continued safe operation, reliable service, and the
implications of any increased financial demands on the customer.
The NARUC resolution is included as Attachment 3 to this report.
The Board of the American Public Gas Association (APGA) has also approved a similar
resolution. APGA is a national trade association comprised of about 600 natural gas utilities
owned and operated by the governments of the communities they serve. The APGA
recognizes the reduction in incident rates over the past two decades, but that serious
distribution incidents continue to occur. They note that assuring the safety of the public living
and working near their pipelines is their number one priority, and resolve that it is appropriate

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for OPS to consider how integrity management principles can be incorporated into
distribution pipeline safety programs. The APGA offers several considerations, including:
• the differences between distribution and transmission pipeline systems described
above,
• the primary role of state regulators,
• actions now taken by operators and states that go beyond minimum regulations,
• the need to recognize potential financial burdens, and
• the need to assure system reliability and continuity of service.
The APGA resolution is included as Attachment 4 to this report.
Finally, last December, the American Gas Association (AGA) Board endorsed addressing
distribution integrity by taking a common sense, risk-based, and technically defensible
approach that would not place an undue burden on consumers. The American Gas Association
represents 195 local energy utility companies that deliver natural gas to more than 56 million
homes, businesses and industries throughout the United States. The AGA committed to
working with State and Federal regulators, pertinent standards bodies, industry and the public
to consider any proposal to enhance the safe, reliable and efficient delivery of natural gas.
These actions reflect the long-standing commitment of industry and government to safe
operation of the nation’s 1.9 million mile natural gas pipeline system. Regulators, legislators
and pipeline operators independently and jointly have been examining natural gas distribution
practices to determine the most effective approach to distribution system integrity and safety.
In developing recommendations for an effective, systematic approach to distribution integrity,
it is vital to take into account the unique characteristics and functions of gas distribution lines.
The following principles apply to this program:
1. Improving the integrity and safety of the Nation’s distribution infrastructure will
require further strengthening of the relationship among State regulators, Federal
regulators, operators, the public and others who have a role to play in pipeline safety.
This improvement should be based on recognition of a shared interest in improving
safety and on enhanced openness in achieving this improvement
2. Distribution integrity management should be based on the threats to distribution
safety, as well as how existing regulations and practices address these threats.
3. States should exercise their prerogative to choose how they regulate distribution
pipeline safety, consistent with their specific needs, including their ability to establish
regulations that exceed the minimum Federal requirements.
4. Any process identified for distribution integrity must be risk-based, technically
defensible and cost beneficial.

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5. Any new regulation must consider the added financial burden placed on the consumer,
as well as the impact of expenditures by municipalities on resources available for other
community safety improvements.
6. Any new integrity management provisions must ensure continued reliability of service
to the consumer.
7. Progress in implementing improvements should be measurable from the current
baseline level.
8. The approach to identifying improvements to distribution integrity should be a
consensus process that includes the involvement of State and Federal regulators,
pertinent standards bodies, industry and the public.
9. Any new integrity management provisions must recognize that there are significant
structural, geographic and functional differences between gas transmission and
distribution systems.
6. Plan and Schedule for Defining and Implementing Distribution Integrity
Management Requirements
Defining and implementing distribution integrity management requirements is a multi-phased
effort intended to develop an approach that will address the three elements of the strategy
described by the DOT Inspector General:
• understand the infrastructure,
• identify and characterize the threats, and
• determine how best to manage the known risks (prevention, detection and mitigation).
The first phase, being conducted during calendar year 2005, involves actively seeking out
additional information about the issues affecting distribution system integrity. PHMSA is
evaluating the history of the spectrum of relevant threats to identify trends and is searching
out those risk control practices that are being used effectively today by some operators and
that can be advanced for broader application in the distribution industry, appropriate to the
specific circumstances of individual distribution pipeline systems.
During this phase, PHMSA is working with a number of groups comprised of state pipeline
safety regulators, pipeline operators, and representatives of the public. These groups augment
PHMSA resources, allowing us to draw on dozens of experts. Those participating in these
groups are themselves supported by technical staff in their parent organizations. The groups
are thus bringing to bear the extensive knowledge of the companies that operate distribution
systems and the state regulators who are most directly involved in their oversight. These
groups are gathering data and making technical findings in a number of areas that will inform
PHMSA efforts in phase 2. There are four work/study groups:

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20
• Data group – evaluating existing data and collecting more data as needed to identify
the nature, significance, and trends in threats affecting distribution pipeline systems
and the effectiveness of current programs addressing these threats
• Risk Control Practices group – identifying the applicability and effectiveness of
practices currently being used to control risk, whether required by State or federal
regulations or implemented voluntarily by operators
• Excavation Damage Prevention group – considering more specifically actions that
have been effective in addressing the most significant threat affecting distribution
pipeline systems
• Strategic Options group – considering means by which effective risk control practices
can be implemented across the broad range of distribution pipeline system operators
and gathering data on the costs and benefits of doing so
A Coordinating Group consisting of the chairman of the NARUC pipeline safety committee,
officers of NAPSR, and managers from the major trade associations facilitates the discussion
and assures that the work/study groups have necessary administrative and technical support.
An Executive Steering Group that includes State Commissioners responsible for pipeline
safety regulation, distribution company officers (from corporate operators), senior managers
(from municipal operators), a public representative, and executives from AGA and APGA
provides high-level input incorporating the perspectives of their respective organizations.
All group meetings are open to the public to maximize the broadest possible input. Meeting
locations and agendas are posted on a public web site10. The web site also provides public
access to all of the information discussed during group meetings and to written documents
that the groups develop. Members of the public can submit comments via the web site and
will be given a specific opportunity to hear about the activities of these groups and to provide
comments during a public meeting scheduled to be held in September 2005.
The Executive Steering Group met for the first time on March 16, 2005, and discussed a
number of high-level options for which detailed information should be gathered (see Section
7). The work/study groups met for the first time March 29-31, 2005, and met for a second
time May 17-19, 2005. The work/study groups are also conducting teleconferences,
collecting information from existing databases and from operator/state participants and
preparing written records of their consideration. As described above, these records are being
made available to the public via the web site. These initial meetings have identified a
developing consensus around a small number of elements that would be appropriate for
distribution integrity management requirements and the continuing process is helping clarify
what those elements would entail.
The action plan describing the activities of the distribution integrity management work/study
groups is provided as Attachment 5.
10 http://www.cycla.com/dimp

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21
PHMSA/OPS will use the information developed by the work/study groups during Phase 1 to
develop appropriate requirements, and to develop or sponsor development of guidance, during
Phase 2. Phase 2 will be conducted during calendar year 2006.
7. Options Being Considered
In preparation for the work of the distribution integrity management work/study groups, OPS
solicited views on the options available to address the issues raised by the DOT Inspector
General in 2004 and to better assure distribution system integrity. OPS considered
information generated during the rulemaking concerning gas transmission pipeline integrity
management, consulted with our State partners and the industry trade associations, and
elicited public views through a public meeting held in Washington, DC, on December 16,
2004. Seven high-level options were identified for consideration:
Option 1. Structured Nationwide public education program, similar to the Smokey The
Bear campaigns, directed at reducing incidents of outside force related to excavation
and highlighting 3-digit dialing to one-call centers
Option 2. Model State legislation, potentially imposing requirements on excavators and
others outside the regulatory jurisdiction of pipeline safety authorities
Option 3. National guidelines or consensus standards, providing guidance to states and
operators for implementing integrity management approaches
Option 4. Guidance documents for adoption by States, similar in scope to option 3 but
with the intent of states mandating use of the guidance
Option 5. Risk-based, flexible, performance-oriented Federal regulation, establishing
high-level elements that must be included in integrity management programs
Option 6. Prescriptive Federal regulation, specifying in detail actions that must be taken
to assure distribution pipeline integrity
Option 7. Development of innovative safety technology, to provide means not now
available for addressing the integrity of distribution pipelines
OPS discussed these options with the distribution integrity management Executive Steering
Group (described above) at its March 16, 2005, meeting. The preponderance of views within
that group was that four of the options, in combination, were worthy of more intensive near-
term consideration. These were options 1, 3, 5, and 7.
• Option 1 – a Nationwide education program – this would address persons outside the
jurisdiction of pipeline safety regulators (e.g., construction excavators and other
parties) who represent a significant portion of the risk to distribution pipelines. These
persons would be unaffected by any changes to pipeline safety regulations.
• Option 5 – a high-level framework outlined by a rule, implemented in conjunction
with more detailed guidance (Option 3) − this would establish basic requirements
while allowing states the flexibility to accommodate the unique needs of different
geographic areas and different communities of operators.
• Option 7 – continued investment in research and development – this could help to
develop new methods of inspecting the networks of small-diameter pipelines, of
varying materials, which constitute distribution pipeline systems.

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The comments made by the Executive Steering Group suggested that Option 2, model State
legislation, could be of interest but is likely of less immediate importance. State legislation
also could address, as does Option 1, constituencies outside regulatory jurisdiction that pose
risks to pipelines (e.g., those excavating in the vicinity of pipelines) but with mandatory
requirements and enforcement options. Option 4, guidance adopted by States, also has
potential for later use, if states find it appropriate to mandate use of all or portions of the
guidance that would be developed under Option 3.
Only Option 6, a prescriptive Federal regulation, was regarded by most Executive Steering
Group participants as being less useful. The comments expressed at the December 16, 2004,
public meeting also reflected general agreement on this point. The comments in both cases
pointed to several reasons that establishing prescriptive requirements that would effectively
and efficiently address distribution integrity would be very difficult, or perhaps impossible.
As described above, there is significant diversity among distribution pipeline operators and
the systems they operate. This makes it less feasible for a single prescriptive regulation to
establish requirements appropriate for all situations. Requirements appropriate for one class
of operators might be ineffective and/or inefficient for others. For example, an analytical risk
model that might be appropriate for a large system, installed over an extended period and that
includes many different pipe materials, could be unnecessary for a small system consisting of
a single type of material installed over a limited period. Requiring that the smaller system
operator implement such a risk model would pose a significant burden, for no safety benefit.
The combination of a high-level Federal rule (Option 5) with guidance (Option 3) could help
assure the flexibility needed to address the wide variations in the gas distribution pipeline
community. Figure 2 is intended to depict how this combination might be structured.

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Figure 2 - Relationship among Federal Requirements, Standards or Guidelines, and
State Requirements
High-Level
Performance Requirements
(Federal Regulation)
Acceptable Methods to
Address Requirements
(Broadly Accepted Guidelines Or
National Consensus Standards)
State-Specific Requirements
Satisfying Federal Requirements and
Referencing Standards or Guidelines
(State Regulations)
Operator-Specific Implementation Requirements
(State-Determined; Allowing Appropriate Cost Recovery)
As depicted in Figure 2, a Federal regulation could be used to establish the high-level
performance requirements driving safety improvement. An example of such a set of
requirements is contained in Figure 3 below. Because the requirements in this example are
very high-level and require implementation of a set of management practices, some set of
standards or guidance likely would be needed to describe how these requirements might be
satisfied by any of the spectrum of regulated distribution pipeline operators. A proven
approach to describing optional implementation approaches that are satisfactory to the
industry and regulatory communities is the development of national consensus standards.
Another proven alternative, which seems preferable at this time, would be development of a
set of guidelines, again describing acceptable implementation options.

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A Report to the Congress: Assuring the Integrity of Gas Distribution Pipeline Systems
Figure 3 - Example High-Level Federal Performance Requirements
24
1. 2. 3. 4. 5. 6. 7. The operator shall develop a program plan that describes how it manages the
integrity of its distribution system, focusing on how it will satisfy the requirements
below.
The operator shall identify threats applicable to its system.
The operator shall characterize the relative significance of applicable threats to its
piping system.
The operator shall identify and implement appropriate practices (or modify current
practices) to prevent, and mitigate the risk from applicable threats consistent with
the significance of these threats.
The operator shall develop and monitor performance measures to allow it to evaluate
the effectiveness of improvements implemented.
The operator shall periodically evaluate the effectiveness of its program and make
adjustments dictated by its evaluation.
The operator shall periodically report to the jurisdictional regulatory authority a
select set of performance measures.
For the vast majority of gas distribution pipeline systems, the States are the jurisdictional
regulatory authority. States adopt Federal regulations and, in the process, have the choice
either to adopt them as stated, or to expand and focus these requirements to clarify acceptable
implementation approaches or address specific State needs. The approach in Figure 2 shows
how the States could draw upon the set of standards or guidelines, developed specifically to
describe implementation choices, to clarify their expectations on how operators would satisfy
the requirements. By explicitly referencing the guidelines or standards, the States could
minimize the operators’ uncertainty on how the requirements might acceptably be
implemented. States might also describe different implementation approaches as acceptable
for each type of operator or type of pipeline under their jurisdiction. Such an approach would
explicitly recognize the differences among States and among operators within a single State.
The bottom element in Figure 2 is included to recognize the fact that many distribution
pipeline operators are subject to rate regulation. Such regulation should explicitly recognize
the cost of implementing new requirements designed to allow their systems to be operated
more safely. Therefore, increases in operating and maintenance costs, as well as costs of
capital improvements, should be addressed in ratemaking for the operators subject to any new
safety related regulations.
In fleshing out appropriate actions to implement high-level performance requirements such as
those listed in Figure 3, it will be necessary to bridge the gap between those requirements and
the guidance/standards that will be needed. The work/study groups will need to identify the
questions that operators and state regulators must answer to assure that the performance-based
requirements are being fulfilled. These questions, in turn, will inform findings regarding the
number and nature of guidelines or standards that are needed.
PHMSA/OPS has preliminarily concluded that this approach will be used to establish
distribution integrity management requirements. The distribution integrity management

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25
work/study groups are directing their primary focus on gathering and analyzing information to
help clarify the elements that would be most effective in such a combination of requirements
and guidance. OPS will consider the results of work/study group activities in its development
of requirements in Phase 2, as described above, and could revise its conclusion regarding the
preferred approach if work/study group activities identify unforeseen reasons why this
approach might not be effective.
Specific Attention to Excess Flow Valves
Excess flow valves (EFVs) are an additional mitigation element that will be considered as part
of this program. EFVs are devices that can be installed in each service line and that may shut
off gas flow if the line is severed downstream of the valve. They represent a measure that
may mitigate the consequences of some incidents if they occur despite the preventive actions
that may be taken to reduce the chances of that happening. In this regard, their use would be
similar to additional preventive and mitigative measures that operators of hazardous liquid
and gas transmission pipelines are required to consider as part of the integrity management
regulations applicable to those pipelines, such as emergency flow restricting devices for
hazardous liquid pipelines or automatic/remote control valves for gas transmission.
EFVs have received a significant amount of attention as a mitigation option for gas
distribution systems. At present, 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.11 In lieu of this notification, operators may elect to voluntarily install the
valves, 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 valves if the customer agrees to pay for the cost of such installations. Discussions
with operators have identified that some distribution system operators are installing the valves
as a routine part of new and replaced service installations in situations in which they apply.
The National Transportation Safety Board has made several recommendations regarding the
use of EFVs in new construction and replaced pipelines. Organizations representing fire
fighters and fire chiefs have expressed support for increased use of the valves, believing that
their use would contribute to public safety and could reduce the number of fire fighter injuries
that occur when gas contributes to the magnitude of fires to which they must respond. OPS is
conducting additional studies on the effectiveness of the valves and on the experience that has
been gained as a result of their use.
Further study is needed. EFVs would not mitigate all incidents occurring on service lines.
The valves are designed to operate in the event of line ruptures that result in major flow of
gas. 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. OPS asked Allegro Energy Consulting to review OPS
11 49 CFR 192.383

<<<PAGE 29>>>

A Report to the Congress: Assuring the Integrity of Gas Distribution Pipeline Systems
26
incident report records to estimate how many incidents might have been mitigated by the
presence of an excess flow valve. 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 upper-bound estimate. The incident reports do not include
some information (e.g., gas flow rate) that is necessary to definitively ascertain whether an
excess flow valve would have been effective nor do they include information on whether the
25% of fatalities or injuries in automobile accidents involving gas meter set assemblies could
have been prevented by an EFV shutting off gas flow.
EFVs are one option for mitigating potential gas distribution incidents. The distribution
integrity management Executive Steering Group believes that implementation of any
requirement related to excess flow valves should be done in conjunction with a holistic
approach to integrity management, as was done for preventive and mitigative options in the
hazardous liquid and gas transmission integrity management rules. OPS has directed the
work/study groups described above to further evaluate potential requirements for use of EFVs
as part of a distribution integrity management program, while OPS and NARUC conduct
other data gathering and analysis activities.
8. Conclusion
Integrity management requirements for hazardous liquid and gas transmission pipelines are
focused on physical inspections of the condition of those pipelines in areas where an accident
could result in high consequences. Gas distribution pipeline systems are very different from
these other types of pipelines. Distribution pipeline systems use many different kinds of pipe
material, in varying sizes including very small pipes (e.g., less than one inch in diameter), and
exist in areas in which physical inspection of the pipe is very difficult.
PHMSA/OPS has embarked on a two-phase program to identify alternate means of better
assuring the integrity of distribution pipeline systems. PHMSA/OPS expects this program to
result in publication of high-level requirements in a federal rule that will be augmented by
necessary guidelines or standards. In the first phase, PHMSA/OPS is working with a number
of work/study groups composed of state pipeline safety regulators, industry personnel, and
representatives of the public to identify and analyze information that will help to identify
effective approaches to assuring distribution system integrity. Discussions within these
groups are revealing a developing consensus on the high-level elements that would be
appropriate in such a regulation. In the second Phase, PHMSA/OPS will develop appropriate
requirements and will develop or sponsor development of necessary guidelines or standards.
The first phase of this program will be completed by the end of 2005. PHMSA/OPS expects
that proposed requirements for assuring integrity of distribution pipeline systems will be
published for public comment by the end of the third quarter of calendar year 2006.

<<<PAGE 30>>>

A Report to the Congress: Assuring the Integrity of Gas Distribution Pipeline Systems
27
Attachments:
1. NAPSR State Survey Results -- State Requirements beyond Federal Regulations
Gas Distribution Systems
2. Summary of Allegro Report – Safety Incidents on Natural Gas Distribution Systems:
Understanding the Hazards, April 2005
3. NARUC Resolution on Distribution Integrity Management, February 16, 2005
4. Position of the American Public Gas Association on Distribution Integrity Management
5. PHMSA/OPS Phase 1 Action Plan

<<<PAGE 31>>>

Attachment 1
NAPSR State Survey Results
State Requirements beyond Federal Regulations
Gas Distribution Systems

<<<PAGE 32>>>

State Requirements beyond Federal Regulations
Gas Distribution Systems
Federal Regulations published in 49 CFR Parts 191 and 192 are applicable to all gas
distribution systems in the U.S. Oversight of the safety of most of these systems falls under
State jurisdiction. States can exercise jurisdiction if their pipeline safety programs are
certified under 49 U.S.C. 60105 or if they enter into agreements with the Secretary of
Transportation under 49 U.S.C. 60106. At this time, all states except Alaska and Hawaii are
certified or party to agreements, as is the District of Columbia. States must enforce at least
the federal regulations, but may also impose additional requirements that go beyond those
regulations. States also foster programs that improve pipeline safety outside their regulatory
structure, e.g., via their rate setting process.
The National Association of Pipeline Safety Representatives (NAPSR)12 conducted a survey
of its members to estimate the extent to which they impose requirements or programs that
exceed the federal minimum. The survey consisted of a questionnaire that asked each state
pipeline safety program manger to indicate whether their state imposes additional
requirements or has infrastructure safety improvement programs implemented outside the
scope of their regulations. NAPSR members were asked to provide a brief description of any
positive responses. The survey was conducted over a brief period, and thus was somewhat
limited in the detail provided with responses.
Forty-eight state agencies and the District of Columbia responded to the NAPSR survey. All
but 6 reported some requirements or programs exceeding the federal minimum standards.
• Twenty-five states, or just over half of the respondents, reported that they required
reports of events that need not be reported under federal regulations (20 states) and/or
that they provide enhanced oversight and observation of work/testing on the pipelines
(11 states).
• Eleven states (22 percent) impose additional requirements intended to prevent or
detect damage to the pipeline by outside parties
• Thirteen states (26 percent) impose requirements for leak testing beyond the federal
minimum. Additionally, eleven states (including 8 of the same) impose additional
requirements related to responses to leaks.
• Eight states (16 percent) require more frequent testing or have other additional
requirements related to the odorant that is added to gas in distribution systems to allow
residents to detect leaks before they cause adverse consequences.
• Six states (12 percent) impose additional requirements related to design and
installation.
• Six states (12 percent) impose additional requirements related to training and
qualification of operator personnel.
• Six states (12 percent) impose additional requirements related to cathodic protection
systems used to protect steel pipe from corrosion.
12 NAPSR is an organization consisting of the state pipeline safety program manager from each state that
exercises jurisdiction over pipeline safety.
1

<<<PAGE 33>>>

• Five states (10 percent) require that operator’s Operating and Maintenance plans be
filed with or approved by the state regulator.
• Five states (10 percent) impose requirements related to operating pressures.
• Five states impose additional requirements regarding location of or protection for
customer meters.
• Three states (6 percent) have requirements that operators cap off abandoned service
lines after specified periods.
• Four states extend operator responsibility for maintenance of service/customer lines.
• Four states reported that they exercise authority beyond the scope of the federal safety
regulations in: ordering changes in the public interest, encouraging safety
enhancement through rate cases, and approving 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.
• One state requires that its operators remediate any evidence found of corrosion within
90 days.
• All but one responding state reported that they have more frequent contact and
involvement with operators in their state than does the federal Office of Pipeline
Safety with operators under its jurisdiction.
The most significant area in which states reported actions beyond federal standards was that
of replacement of aging and inferior infrastructure. Thirty-three states, or two-thirds of those
responding, reported that they have some kind of program for replacement of 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.
• Twelve states reported that their programs involved all (or nearly all) operators in their
state.
• Replacement programs reported by sixteen states 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
replacement programs.
• Eight states reported that their replacement programs are complete (i.e., all targeted
infrastructure has been replaced) or will be completed by 2010.
• Eight additional states reported that their replacement programs will be complete by
about 2020.
• Four states reported that their programs would not be complete until after 2020.
• Twelve states did not report an expected completion date.
These results indicate that states can and do exercise authority to go 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
2

<<<PAGE 34>>>

two-thirds of the states, although some of these programs are of limited scope (i.e., affecting a
single operator).
3

<<<PAGE 35>>>

Attachment 2
Summary of Allegro Report
Safety Incidents on Natural Gas Distribution Systems:
Understanding the Hazards
1

<<<PAGE 36>>>

Safety Incidents on Natural Gas Distribution Systems:
Understanding the Hazard
Introduction and Summary
Introduction and Summary
Background to Study
Undertaken for the
Office of Pipeline
aluates the safe
fety, this stuc
record of gas
contracted with Allegro Energy Consulting to undertake this work as
distribution systems
part of the agency's multi-faceted initiative to improve the safety
more fatalities and injuries than the other types of pipelines that the
are in the news because of incidents involving explosions and
agency regulates (gas transmission and hazardous liquid), and often
evacuations, a fact that has focused the attention of regulators, the
Congress, industry and the public.
Understanding the
Strategies for improving the safety performance can only be developed
a central goa
diverse hazards wa
in detail the information provided by the industry to the OPS regarding
after examining the record. This report takes this first step, examining
reportable safety incidents. That information was then reclassified into
the diverse hazards reflected in the record. With the better
understanding of the hazards - the causes and circumstances
surrounding the incidents — a broad partnership of stakeholders can
develop more finely targeted strategies to manage and control the risks
involved. The ultimate goal is to prevent incidents from occurring.
Data for this study
Data for this report are drawn mainly from the Department of
vailable on th
om DOT's PHMSA
Transportation's Pipeline and Hazardous Materials Administratio:
"PHMSA"). which is the primary Federal regulator of the safety
internet
related aspects of natural gas pipeline operations through its Office of
om the agener's website, http://ops.dot.go
ipeline Safety ("OPS"). Most of the data have been taken direct
' PHMSA, established in February 2005, is the successor agency to Research and
Special Programs Administration ("RSPA").
Allegro Energy Consulting
1

<<<PAGE 37>>>

Safety Incidents on Natural Gas Distribution Systems:
Understanding the Hazards
Introduction and Summary
Gas Distribution System Is All Most Consumers Know of Gas
Distribution utilities
the American public. Natural gas distributors operate a million miles
The natural gas distribution system is central to the energy supply for
are everywhere
of mains and over 56 million "services" - connections to consumer's
million miles o
meters. Through this network, energy flows to provide heat to
mains and over 56
residences, commercial establishments like businesses, churches, and
million services
end-users, distribution is the gas supply system, since its mains and
schools, and to power manufacturing plants and industry. To most
production and processing facilities and gathering and transmission
pipelines - are also vital, but are largely invisible to the consuming
people live, so
Concentrated where
Necessarily, gas distribution systems must be concentrated where
increased likelihood
gas distributors because of this high concentration of pipeline
failures
of consequences of
presents the increased possibility that any failures in the system coul
geterane genedity o the challenge is the pact at sch are intes and
ithin the distribution operator's contro
Highlights of Findings
From 1985-87, there were an average of 170 reportable incidents per
vear on the nation's gas distribution systems, and from 2001-03
there were an average of 124 per year. While this is a 27% decline
the improvement in the record was concentrated in the earty years.
Over the 1985-2003 period, there were also an average of 11 gas
distribution incidents per year that involved a fatality, and an
fatality, while small in number, did not show a sustained downward
average of 43 per year that involved an injury. Those involving a
but not steadily:
trend. Incidents involving an injury have trended downward overall,
Over the 1999-2003 period, the focus of this report, there were 634
incidents reported by gas distribution operators on PHMSA Form F
7100.1, for an average of 127 per year. Over the five years, there
were 40 incidents involving a fatality, and 181 incidents involving an
injury.
Allegro Energy Consulting
2

<<<PAGE 38>>>

Safety Incidents on Natural Gas Distribution Systems:
Understanding the Hazards
Introduction and Summary
The PHMSA incident reporting form in use until early 2004
employed cause categories that were too broad to assess the real
hazards that were involved in natural gas distribution incidents.
reported cause for 61% of the incidents from 1999-2003, but this
On the oid form, pre-revision, Damage by Outside Force was the
cause category is really a group of disparate hazards. The category
"Other" was the reported cause of 25% of the incidents; this catchall
obscures information vital to understanding the real cause.
incidents involving a fatality and 73% of the incidents involving an
Furthermore, these two categories accounted for 90% of the
injury.
For this report, Allegro Energy Consulting used the operator's
narrative filed with the PHMSA Form F 7100.1 over the five year
period 1999-2003 to reclassify the incidents from the five cause
categories in use that time to the 7 first-level and 25 second-level
cause categories in use since the form's revision in early 2004.
Excavation and Mechanical Damage and Other Outside Force are
still the largest cause categories but the separation is crucial for the
insight necessary to address the underlying issues.
The reclassification effort succeeded in moving 60% of the incidents
formerly classified as "Other" into a more meaningful category.
The new combined category of Miscellaneous/Unknown (the revised
version of Other causes) now accounts for just 12% of incidents.
The new 25 second-level cause categories, combined with other
information such as the part of the system involved, provide much
information for consideration in developing strategies to address the
safety record.
Excavation/Mechanical Damage accounts for 38% of the incidents,
Call statutes. Most of these incidents occurred on Mains and Service
75% of which involved the kinds of activities that are subject to One-
Lines. This category was also the largest cause of incidents involving
injuries. Participants in One-Call programs - the entities who pay for
the programs such as electric, phone, cable, and water utilities -- are
among the parties causing the damage. Thus, strategies to address the
issue may involve stricter enforcement of One-Call statutes, but will
also require involvement, and cooperation, of these other utilities. In
fact, almost 10% of the Excavation/Mechanical Damage incidents are
caused by operators themselves (or their contractors), so additional
training or behavior changes may be required. Another issue is
tradesmen such as plumbers, where One-Call statutes are not relevant,
but where additional "good practices" may be needed.
Allegro Energy Consulting
3

<<<PAGE 39>>>

Safety Incidents on Natural Gas Distribution Systems:
Understanding the Hazards
Introduction and Summary
Fire/Explosion as the Primary Cause ("Fire First" in this report)
accounts for 11% of the incidents. In these incidents, a fire caused by
sound natural gas system. During the 1999-2003 period, the guidance
other factors such as faulty wiring secondarily involves an otherwise
in the instructions for Form 7100.1 directed operators not to report
these incidents "unless the damage to facilities subject to Part 192
exceeds $50,000. " Since most damage is to residences or other
buildings, not facilities subject to Part 192, most of these incidents did
not get reported. Reporting is inconsistent, however, with one utility
accounting for 25 out of the 71 Fire First incidents. The reporting of
cause category. Thus, these incidents must be addressed. Particularly
these incidents will increase, however, since it is now an accepted
since these incidents largely involve non-jurisdictional facilities, and
facilities outside the operator's control, formulating an effective
strategy for dealing with the incidents will require a broad partnership
of stakeholders.
incidents, 2/3 of them involving Meter Set Assemblies. These
Vehicles Unrelated to Excavation Activity cause 11% of the
incidents are an excellent illustration of the difference between the
hazards faced by the gas distribution system and other pipeline types
that PHMSA regulates, such as gas transmission and oil pipelines.
Vehicles were involved in 25% of the incidents causing a fatality, the
largest share of any of the 25 causes. Again, only a coalition of
stakeholders can develop an approach to reducing these incidents.
Non-jurisdictional assets or facilities are also an issue in the
incidents involving "Miscellaneous" causes, where 23 out of 40 (at
least) occurred on customer piping or appliances.
Operator Error, which accounts for just 6% of all reportable
incidents, causes 16% of the incidents involving an injury, an over-
representation.
This examination clearly points out many ways that the hazards
faced by gas transmission and oil pipelines, often outside of the
causing gas distribution incidents are diverse, different from those
operator's control, and often outside of the regulatory reach of the
Office of Pipeline Safety. Because these incidents clearly have a
societal impact, in deaths, injuries, property damage, burden on first
responders in the community, and in a host of other ways, they must
be addressed, however. Formulating a set of strategies that will
reduce their occurrence and mitigate their impact will require a
broad partnership of stakeholders.
Allegro Energy Consulting
4

<<<PAGE 40>>>

Safety Incidents on Natural Gas Distribution Systems:
Understanding the Hazards
Summary
Summary and Conclusions
This examination of satety incidents filed by gas distribution operators
are central to understanding the performance of these systems:
on PHMSA Form F 7100.1 has highlighted a number of factors that
• The conventional wisdom that the preponderance of gas
distribution incidents are caused by outside force damage is
correct, but is based on categories that are too broad to allow the
development of effective strategies for performance improvement.
• By reclassifying incidents to the 7 first-level and 25 second-level
to see the diversity of hazards involved in reportable gas
cause categories of the revised PHMSA Form F 7100.1, we begin
distribution incidents.
• Excavation and Mechanical Damage, while it accounts for the
greatest face Damage, sat 3 includes part or thated incidenther
and incidents caused by an existing fire or explosion unrelated to
Dutside Force Damage,
ncidents. and caused the largest share of incidents (73%
le gas system, is also important. It accounted for 29% of a
involving a Meter Set Assembly.
In fact, Other Outside Force Damage causes the highest share of
ncidents involving a fatality - 40%. Vehicle-related incident
lone, a subset of Other Outside Force Damage, account for 25%
of the incidents involving a fatality.
• The largest cause of incidents involving an injury is Excavation
and Service Lines.
and Mechanical Damage, and they occurred primarily on Mains
• Reclassification of the old category "Other," which formerly
accounted for 25% of the incidents, successfully distributed more
The remaining incidents classified as Miscellaneous illustrate the
than half of the incidents to a more meaningful cause category.
incidents. Some of these occurred on customer piping, outside of
diversity of the hazards involved in the gas distribution safety
OPS jurisdiction.
The issue of OPS jurisdiction is also important in the Other
Outside Force Category, some of which involved customer piping,
and some of which reflect the secondary involvement of the gas
system during an unrelated fire.
Allegro Energy Consulting
30
5

<<<PAGE 41>>>

Safety Incidents on Natural Gas Distribution Systems:
Understanding the Hazards
Summary
• There is inconsistent reporting of incidents that involve facilities
problems. For instance, the data cannot be compared state-to-state
outside of OPS jurisdiction. The inconsistency carries a variety of
or utility-to-utility. Furthermore, the inconsistency also obscures
the real picture of failures on gas distribution systems, and thus the
data can only be used with extreme caution in measuring, for
instance, the success of regulation in enhancing public safety.
The issue of the incidents on non-jurisdictional facilities highlights the
impacts touch everyone. That the activity or equipment involved in an
fact that the role of natural gas in modern life is such that its safety
incident is outside of DOT jurisdiction (or reportable critera) does not
mean that the incident did not occur, or that it did not have an impact
on people, communities and their resources. It does mean that the
hazard that caused the incident is unlikely to be "fixed" with the wave
of DOT's regulatory wand, or operator qualification standards, or even
the most strictly enforced One-Call statutes.
Because of the diversity of the hazards, as well as the jurisdictional
issues, only a broad partnership of stakeholders will succeed in
developing the breadth of programs that might improve the record and
prevent deaths and injuries as well as property damage and other
consequences. Such a broad approach may be one way to address the
underlying issues without heavy-handed regulation, or protracted
debate that comes with trying to assign blame among different parties.
This partnership might include:
• DOT
Operators and their trade associations and education foundations
• States, including State Fire Marshals, utility regulators, pipeline
safety regulators
•
•
Other utilities (electric, telephone, cable, water, sewer)
• Damage prevention organizations such as Common Ground
Building trades; developers; architects; City/town zoning boards
Alliance
• Insurers and insurance underwriters
• Homeowners and other customers
This report reviews the safety record and in so doing, identifies some
Allegro Energy Consulting
31

<<<PAGE 42>>>

Attachment 3
NARUC Resolution on Distribution Integrity Management
February 16, 2005
1

<<<PAGE 43>>>

Resolution on Distribution Integrity Management
million mile natural gas pipeline system with outstanding reliability and safety; and
WHEREAS, Industry and government have long been committed to operating the nation's 2.2
WHEREAS, Regulators, legislators, and natural gas distribution pipeline operators have
the most effective approach to maintaining and enhancing distribution system integrity and
independently, as well as jointly, been examining natural gas distribution practices to determine
safety; and
WHEREAS, State regulatory agencies have primary responsibility for regulating natural gas
distribution pipeline safety and play a critical role in ensuring distribution integrity and in
meeting the unique demands of their State's energy needs; and
WHEREAS, When developing regulation, State regulatory agencies must take into account their
State's varying geography, energy customer base, local economy, system age and materials of
construction, size and complexity of distribution operations, and consumption patterns of natural
gas customers ranging from large-volume manufacturers to mid-size businesses to single-family
residences, as well as the State's overall executive policies and goals; and
WHEREAS, There are significant structural, geographic and functional differences between gas
transmission integrity management requirements to natural gas distribution systems; and
transmission and distribution systems, and these differences make it infeasible to apply many
WHEREAS, Any adjustment to an operator's distribution integrity management program should
be responsive to that operator's distribution system safety performance, existing regulations and
current practices that can affect such performance, and
the Natural Gas Distribution Infrastructure, presents results based on a consensus between
WHEREAS, The American Gas Foundation study entitled, Safety Performance and Integrity of
beginning to determine effective approaches to improving distribution integrity management;
industry and government stakeholders, including NARUC, thus providing an appropriate
now therefore be it
RESOLVED, That the Board of Directors of the National Association of Regulatory Utility
Commissioners (NARUC), convened at its February 2005 Winter Meetings in Washington, DC,
encourages States, the Federal Office of Pipeline Safety, gas distribution pipeline operators, and
other stakeholders to develop an approach to distribution integrity management that uses risk-
based, technically sound and cost-effective measures, which reflect that stakeholders are:
knowledgeable of the infrastructure; can identify threats against their systems; and can take
continued safe operation, reliable service and the implications of any increased financial
appropriate measures to reduce the risk of system failures while balancing the needs to ensure
demands on the consumer.
Sponsored by the Committee on Gas
Adopted by the NARUC Board of Directors February 16, 2005
1

<<<PAGE 44>>>

Attachment 4
Position of the American Public Gas Association on Distribution Integrity
Management
1

<<<PAGE 45>>>

Position of the American Public Gas Association on
Distribution Integrity Management
The American Public Gas Association (APGA) is a national trade association comprised
of about 600 natural gas utilities owned and operated by the governments of the
communities they serve. APGA and its members believe that:
1. Assuring the safety of the public living and working near our natural gas distribution
mains and services is our number one priority,
2. The number of serious distribution incidents has declined sharply over the past two
decades, yet serious distribution incidents, primarily caused by excavators, still occur,
3. Integrity management principles can be applied to distribution piping systems to
potentially further improve distribution pipeline safety,
4. Historical data has been analyzed in a study by the American Gas Foundation to
quantify on a national level the causes and consequences of distribution incidents, and
5. Threats to and inspection and mitigation techniques available for distribution piping
systems are markedly different than those of transmission piping systems,
Therefore, the American Public Gas Association resolves that:
It is appropriate for the Research and Special Programs Administration (RSPA) to
consider how integrity management principles can be incorporated into its distribution
pipeline safety programs.
In considering incorporating integrity management principles into its distribution pipeline
safety programs RSPA should consider:
1. That significant differences exist between distribution and transmission piping
including size, pressure, materials, threats, feasible inspection technologies and other
factors that will require a different approach than was used for integrity management
of gas transmission and hazardous liquid pipelines,
2. That distribution piping is primarily regulated by states which can and in many cases
have enacted additional requirements above and beyond federal regulations,
3. That many distribution operators have either voluntarily or by agreement with states
implemented integrity management programs addressing specific threats,
4. The relative significance of each specific threat to distribution piping systems,
5. The prevention and mitigation techniques available for these distribution-specific
threats,
6. The effect prevention and mitigation techniques will have on system reliability and
continuity of service,
7. The extent to which current state and federal pipeline safety regulations and operator
programs address specific threats to distribution piping systems,
8. The financial impacts of any new requirements on gas customers already reeling under
high gas prices, and
9. The financial and administrative burden any new requirements will impose on
operators, particularly on small entities.
1

<<<PAGE 46>>>

Attachment 5
PHMSA/OPS Phase 1 Action Plan
1

<<<PAGE 47>>>

Distribution Integrity Management
Phase 1 Action Plan
Products
Interim findings will be produced by June 2005. Final products for Phase 1 will be available
in December 2005. The interim findings will address:
• Options selected for examination and expected areas of application,
• Scope of guidance or standards identified as necessary to support assurance of
integrity management,
• Guidance or standard development organizations identified (if needed).
The principal final product from this effort will be an assemblage of data, information, and
analyses that support a set of activities that could be promulgated within regulations, guidance
and standards. Supporting products will include:
• Description of existing regulations at the State and Federal levels and identification of
areas in which additional regulations could contribute to distribution safety,
• Description of existing practices that go beyond the regulations, their areas of
applicability, and an initial characterization of their effectiveness,
• Summary of what existing leakage and incident data tell us about threats to safety, and
recommendation of additional data that should be assembled and analyzed to support
improving distribution safety performance,
• Findings for consideration by guidelines or standards development organizations on:
o The scope of guidelines/standards needed,
o The elements or features that need to be addressed in each standard/guideline,
o The range of operator or pipeline types,
o The timeframe on which the standards/guidelines are needed.
• Information to support the evaluation of the costs and benefits associated with
practices that are candidates for incorporation in standards or guidelines,
• Analysis of available experience with EFVs including:
o Conditions under which their application is considered feasible and potential
beneficial,
o Experience with their performance and effectiveness,
o Costs and benefits of installation and operation.
• Documentation of consideration of alternative options.
Work/Study Groups:
Work/study groups have been assembled to address specific issues related to identifying and
characterizing approaches to improve the safety of distribution pipeline systems.
Representation on each group consists of at least one NAPSR and one industry person
together with other representatives selected for their particular expertise in the areas to be
investigated by the group. Each group includes representation from small operators to ensure
1

<<<PAGE 48>>>

access to their perspectives. Representatives of the public participate on work/study groups.
A separate group with responsibilities as described will address each of the areas below.
1. Strategic Options Group - This group will:
a. Initially identify candidate options to implement improvements in distribution
system safety,
b. c. Identify areas of applicability associated with each option,
Considering information from the other groups, suggest methods by which
selected approaches to improve distribution safety might best be implemented,
d. Identify candidate program performance measures that will support evaluation
of the impact of implementing integrity management requirements,
e. Provide findings on the scope and elements to be identified for any standard or
guidance development efforts suggested by the group.
Approaches resulting from this program could include educational initiatives,
technology development, standards or guidance development, and regulatory or
legislative initiatives. Strong consideration will be given to state-identified
approaches to facilitate the implementation of the desired safety improvements.
The strategic options group will also gather data and estimate costs and benefits of
various approaches to improve distribution safety, including practices currently in
place in various states. Information gathered will include available cost/benefit
analysis used to support cost recovery allowance for practices currently considered to
be effective.
2. Risk control practices group - This group will identify and evaluate the applicability
and effectiveness of current regulations (Federal and State) as well as current risk
control practices and programs employed by government and industry to address the
spectrum of threats to the safety of distribution pipeline systems. For activities
identified as candidate requirements and practices, the group will identify the industry
segments to which they are most applicable. A separate group will address the outside
force/excavation threat. In addition, this group will:
a. Identify gaps in current regulations, standards and practices, and the threats
they are designed to address;
b. Develop information concerning current practices for prevention, detection,
and mitigation of applicable threats;
c. Review and characterize available models and practices used to evaluate and
integrate information to support decisions on applicability of threats, useful
risk management measures, and segment priority for implementing safety
improvements;
d. Identify and evaluate current and potential approaches for the use of financial
incentives to advance safety improvements;
e. Identify and evaluate current practices, consensus standards and guidance on
EFV installation, testing and maintenance; and
f. Provide findings on the scope and elements to be identified for any standard or
guidance development efforts suggested by the group.
2

<<<PAGE 49>>>

3. 4. Data group - This group will assemble existing information, including studies, to
identify the nature, significance, and trends in threats affecting distribution pipeline
systems. It will also assemble information and evaluate the effectiveness of current
programs addressing those threats. In carrying out its work, the group will identify the
industry segments to which data are applicable. In addition, this group will:
a. Evaluate data for each State to determine if any significant differences or
similarities exist that may impact the findings of this program;
b. Determine whether and to what extent data other than incidents should be
considered (e.g., data on the physical characteristics, location, physical
environment, and protection of existing pipelines may support understanding
of the nature and management of threats to integrity);
c. In cooperation with the strategic options group, identify candidate changes in
reporting requirements to facilitate future evaluation of the effectiveness of
actions implemented as a result of this plan;
d. Identify and evaluate performance data on EFVs (e.g., numbers installed,
incidents mitigated, EFV malfunctions) from those states where extensive use
of EFVs has been made. Where possible, the impact on EFV performance of
local criteria and guidance for design, installation and maintenance will be
considered;
e. Determine whether data can be used to characterize the risk from the spectrum
of distribution operators. These data could potentially influence the nature of
requirements for the smallest operators; and
f. Provide findings on the scope and elements to be incorporated in any standard
or guidance development efforts suggested by the group.
Excavation damage prevention group – This group will examine a spectrum of
approaches to achieve increased safety against this threat. This will include evaluation
of the Common Ground Alliance database and related information to identify practices
being used to prevent excavation damage, their effectiveness, and the extent of their
application, identifying the factors of greatest importance in assuring the application
and effectiveness of existing practices, and identifying candidate areas of
improvement based on the breadth of application of the most effective currently
defined practices. In addition, the group will provide comments on the scope and
elements that should be incorporated in any useful new approaches that may be
identified during the group’s activities.
These four work/study groups will be supported by an assigned support staff comprised of
knowledgeable individuals from industry, the States and the Federal regulatory agencies.
3

## Provenance

- Official: Yes
- Source: <https://downloads.regulations.gov/PHMSA-RSPA-2004-19854-0074/attachment_1.pdf>
- Source ID: `regulations-gov`
- SHA-256: `4e22defbc601224db3e8040132731d1df185864231e777068ac6dfe98b1f5e74`
- Retrieved: 2026-08-20T02:22:46.679Z
- Exported: 2026-08-24T11:08:58.028Z
- Document slug: `regulations-gov-attachment-0900006480e836bd`

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