Pipeline Safety: Integrity Management Program for Gas Distribution Pipelines, 36015-36034 [08-1387]

Agencies

• Pipeline and Hazardous Materials Safety Administration
• DEPARTMENT OF TRANSPORTATION

[Federal Register Volume 73, Number 123 (Wednesday, June 25, 2008)]
[Proposed Rules]
[Pages 36015-36034]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 08-1387]


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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Part 192

[Docket No. PHMSA-RSPA-2004-19854]
RIN 2137-AE15


Pipeline Safety: Integrity Management Program for Gas 
Distribution Pipelines

AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA), 
Department of Transportation (DOT).

ACTION: Notice of proposed rulemaking.

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SUMMARY: PHMSA proposes to amend the Federal Pipeline Safety 
Regulations to require operators of gas distribution pipelines to 
develop and implement integrity management (IM) programs. The purpose 
of these programs is to enhance safety by identifying and reducing 
pipeline integrity risks. The IM programs required by the proposed rule 
would be similar to those currently required for gas transmission 
pipelines, but tailored to reflect the differences in and among 
distribution systems. In accordance with Federal law, the proposed rule 
would require operators to install excess flow valves on certain new 
and replaced residential service lines, subject to feasibility criteria 
outlined in the rule. Based on the required risk assessments and 
enhanced controls, the proposed rule also would establish procedures 
and standards permitting risk-based adjustment of prescribed intervals 
for leak detection surveys and other fixed-interval requirements in the 
agency's existing regulations for gas distribution pipelines. To 
further minimize regulatory burdens, the proposed rule would establish 
simpler requirements for master meter and liquefied petroleum gas (LPG) 
operators, reflecting the relatively lower risk of these small pipeline 
systems.
    This proposal also addresses statutory mandates and recommendations 
from the DOT's Office of the Inspector General (OIG) and stakeholder 
groups.

DATES: Anyone may submit written comments on proposed regulatory 
changes by September 23, 2008. PHMSA will consider late-filed comments 
to the extent possible.

ADDRESSES: Comments should reference Docket No. PHMSA-RSPA-2004-19854 
and may be submitted in the following ways:
     E-Gov Web Site: https://www.regulations.gov. This site 
allows the public to enter comments on any Federal Register notice 
issued by any agency.
     Fax: 1-202-493-2251.
     Mail: DOT Docket Operations Facility (M-30), U.S. 
Department of Transportation, West Building, 1200 New Jersey Avenue 
SE., Washington, DC 20590.
     Hand Delivery: DOT Docket Operations Facility, U.S. 
Department of Transportation, West Building, Room W12-140, 1200 New 
Jersey Avenue SE., Washington, DC 20590 between 9 a.m. and 5 p.m., 
Monday through Friday, except Federal holidays.

[[Page 36016]]

    Instructions: In the E-Gov Web site: https://www.regulations.gov, 
under ``Search Documents'' select ``Pipeline and Hazardous Materials 
Safety Administration.'' Next, select ``Notices,'' and then click 
``Submit.'' Select this rulemaking by clicking on the docket number 
listed above. Submit your comment by clicking the yellow bubble in the 
right column then following the instructions.
    Identify docket number PHMSA-RSPA-2004-19854 at the beginning of 
your comments. For comments by mail, please provide two copies. To 
receive PHMSA's confirmation receipt, include a self-addressed stamped 
postcard. Internet users may access all comments at https://
www.regulations.gov, by following the steps above.

    Note: PHMSA will post all comments without changes or edits to 
https://www.regulations.gov including any personal information 
provided.

Privacy Act Statement

    Anyone can search the electronic form of all comments received in 
response to any of our dockets by the name of the individual submitting 
the comment (or signing the comment, if submitted on behalf of an 
association, business, labor union, etc.). DOT's complete Privacy Act 
Statement was published in the Federal Register on April 11, 2000 (65 
FR 19477).

FOR FURTHER INFORMATION CONTACT: Mike Israni at (202) 366-4571 or by e-
mail at mike.israni@dot.gov.

SUPPLEMENTARY INFORMATION: The following subjects are addressed in this 
preamble:

I. Background
    A. Integrity Management (IM)
    B. Nature of U.S. Distribution Pipeline Systems
    C. Safety of Distribution Pipeline Systems
    D. Distribution Pipeline Safety Regulation
    E. Applicability of Integrity Management Plans (IMP) to 
Distribution Pipeline Systems
    Distribution Systems Are Located in Highly Populated Areas
    Challenges of Assessment or Testing
II. American Gas Foundation Study
III. Recommendations or Mandates of Oversight Bodies
    A. DOT Inspector General
    B. National Transportation Safety Board
    C. Congressional Mandate
IV. Stakeholder Groups
    A. Stakeholder Groups' Involvement
    B. Stakeholder Groups' Findings
    C. Stakeholder Conclusions
    D. Findings Relevant To Leak Management
    E. Stakeholder Considerations Regarding Excess Flow Valves 
Comments From Fire Service Organizations
V. Public Meetings
    A. Public Meetings Concerning Distribution Integrity Management
    B. EFV Public Meeting
VI. Guidance for Integrity Management
VII. Applicability to Small and Simple Distribution Systems; Request 
for Comments
    A. Master Meter and LPG Operators
    B. Very Small Distribution Systems
VIII. Plastic Pipe Issues
    A. Plastic Pipeline Database and Availability of Failure 
Information
    B. Plastic Pipe Marking
IX. Monitoring the Effectiveness of Actions
X. Deviating From Required Intervals Based on Operator's 
Distribution Integrity Management Plan (DIMP)
XI. Prevention Through People
XII. Summary Description of Proposed Rule
XIII. Section-by-Section Analysis
XIV. Regulatory Analyses and Notices

I. Background

A. Integrity Management

    PHMSA is initiating this rulemaking proceeding in order to extend 
its integrity management approach to the largest segment of the 
Nation's pipeline network--the distribution systems that directly serve 
homes, schools, businesses, and other natural gas consumers. Beginning 
in 2000, the agency has promulgated regulations requiring operators of 
hazardous liquid pipelines (49 CFR 195.452, published at 65 FR 75378 
and 67 FR 2136) and gas transmission pipelines (49 CFR 192, Subpart O, 
published at 68 FR 69778) to develop and follow individualized 
integrity management (IM) programs, in addition to PHMSA's core 
pipeline safety regulations. The IM approach was designed to promote 
continuous improvement in pipeline safety by requiring operators to 
identify and invest in risk control measures beyond core regulatory 
requirements.
    The IM regulations for hazardous liquid and gas transmission 
pipelines are similar. Fundamentally, both require that operators 
analyze their pipelines to identify and manage factors that affect 
risks to the pipeline and risks posed by the pipeline. Operators must 
integrate the best available information about their pipelines to 
inform their risk decisions. Both rules require that operators identify 
segments of their pipelines where an incident could cause serious 
consequences and focus priority attention in those areas. Both rules 
also require that operators implement a program to provide greater 
assurance of the integrity of these pipeline segments. Actions required 
in these segments include assessments utilizing in-line inspection 
tools, pressure testing, direct assessment, or other technology that 
provides an equivalent understanding of the pipe condition. While 
existing regulations required prompt repair of safety-significant 
problems, the IM regulations require operators to inspect their lines 
and perform repairs within a period of time commensurate with the 
safety significance of the problems found. The rules also require that 
operators implement measures that will help prevent accidents from 
occurring on their high-consequence segments and that will mitigate the 
consequences if an accident does occur.
    Although it is too early to draw statistically-significant 
conclusions about the effectiveness of the IM programs for transmission 
pipelines, early indications are very favorable. The initial 
inspections under IM have identified tens of thousands of locations 
where the pipelines were damaged (including damage by external force/
excavation and by conditions like corrosion) and repairs were made 
before accidents could occur. Operators have implemented additional 
safety measures to address higher-risk situations, many of which are 
unique to their individual circumstances. These early successes have 
fueled interest in extending the IM approach to gas distribution 
pipeline systems.

B. Nature of U.S. Distribution Pipeline Systems

    As of 2006, more than 1.2 million miles of gas mains are in service 
in the U.S. ``Mains'' are the pipelines providing a common supply to a 
certain number (often hundreds) of homes and businesses. These 
pipelines are often located under city streets and range in size from 
less than 2 inches in diameter to more than 8 inches in diameter. These 
mains feed over 63 million ``services.'' A ``service'' is the pipe that 
connects to a main and delivers gas to an individual customer, at the 
meter. Service lines are usually very small, less than 1-inch in 
diameter except for those serving larger industrial and commercial 
customers. The length of service lines varies widely. In dense urban 
areas where townhouses are built right up to the sidewalk, a service 
line may be only a few feet long. In rural areas, service lines may be 
several hundred feet long, perhaps as long as a mile. PHMSA uses 65 
feet as its estimate of the average length of a service line. Applying 
that value, the 63 million services represent nearly another 800,000 
miles of pipeline, meaning that the total amount of pipeline in U.S. 
distribution pipeline systems is approximately two million miles. Use 
of natural gas continues to grow in the U.S., and the amount of 
distribution pipeline in service increases accordingly. Since 2001, an 
additional 5.1 million customers have been added, representing an 
increase of

[[Page 36017]]

over 173,000 miles of distribution pipeline.
    Natural gas has been distributed by pipeline in some areas for over 
a hundred years. Pipeline systems in these areas were originally small, 
serving a few customers. These systems often merged as larger 
distribution companies were formed. The materials in use in some of 
these systems reflect older (e.g., cast iron, copper, bare steel) as 
well as newer (e.g., polyethylene plastic and cathodically-protected 
coated steel) technologies. Two-thirds of States have programs that 
require distribution pipeline operators to replace older pipe,\1\ but 
much of the pipe in service is still many decades old.
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    \1\ Some of these programs involve a limited number of 
operators, as described further below.
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    In other areas, distribution of natural gas by pipeline is a 
relatively new phenomenon. In some rural areas, for example, gas may 
not have been available until a transmission pipeline was routed into 
the vicinity. Then, municipalities or distribution companies may have 
created a distribution system to bring natural gas service to customers 
for whom it was previously unavailable. Systems of this nature tend to 
be relatively uniform in age and type of materials, but the threats to 
integrity (such as electrical interference from other buried 
substructures and localized flooding or vehicular traffic patterns) may 
still vary from one location to another. Diversity of the gas pipeline 
system will likely increase as systems age, new customers are added, 
and portions of the original systems are replaced. The bulk of newer 
gas distribution pipeline systems, and replacements for older pipe, are 
comprised of plastic pipe. More than half of the pipelines in U.S. gas 
distribution systems are non-metallic.

C. Safety of Distribution Pipeline Systems

    By operation of the Federal Pipeline Safety Laws, 49 U.S.C. 60102, 
the Federal government has assumed ultimate responsibility for the 
safety oversight of distribution pipeline operators. PHMSA's 
regulations in 49 CFR Part 192 establish a minimum set of safety 
requirements that all States must implement, although States may impose 
more stringent requirements on intrastate systems. PHMSA also collects 
data concerning distribution system mileage, incidents that occur on 
distribution systems, their leak repair experience and other 
information about the size, age and material(s) of construction of 
their distribution piping. PHMSA considered this information, its 
historical trends, and projected patterns in proposing IM regulations 
for distribution pipelines.
    Incidents on distribution pipelines kill and injure more people 
than incidents on gas transmission pipelines. As noted above, nearly 
two million miles of distribution pipelines are in operation in the 
U.S., compared with approximately 300,000 miles of gas transmission 
pipelines. In addition, distribution pipelines are almost all located 
in populated areas. Large portions of gas transmission pipelines 
traverse rural areas where there are few people. Largely because of 
these differences, incidents on distribution pipelines in 2006 resulted 
in five times as many fatalities (16 vs. 3) and six times as many 
serious injuries (25 vs. 4) as those on gas transmission pipelines, 
even though the total number of incidents on each type of pipeline was 
about the same (141 vs. 134). Because of the much larger number of 
miles of distribution pipeline, the normalized rate of fatalities and 
injuries (i.e., the number per 100,000 miles) is similar for the two 
types of lines, with a slightly lower rate for distribution lines. As 
described further below, the trend in gas distribution incidents 
involving fatalities and serious injuries (those requiring 
hospitalization) was downward from 1990-2002. In the years since, 
however, the number has again started to increase.

D. Distribution Pipeline Safety Regulation

    Pursuant to Federal law, most oversight of gas distribution 
pipeline systems is performed directly by States. Under 49 U.S.C. 60105 
and 60106, a State may exercise jurisdiction over intrastate gas 
distribution operations within the State if its pipeline safety program 
is certified by PHMSA or if it enters into an agency agreement with 
DOT. Under these provisions, 48 States (excluding only Alaska and 
Hawaii) and the District of Columbia currently exercise safety 
jurisdiction over some or all gas distribution operations within their 
boundaries. States must implement the minimum standards established by 
PHMSA but have a variety of ways in which they can oversee distribution 
pipeline safety. They can simply mirror the Federal pipeline safety 
program; they can impose additional requirements, beyond the Federal 
minimum; they can engage in special oversight programs with individual 
operators or groups of operators; or finally, they can provide 
incentives for safety improvements, often through their rate-setting 
authority.
    It is appropriate that the principal actions for regulating 
distribution pipeline safety rest with the States. States need to 
balance safety and affordability. They need to ensure that the 
particular needs of their citizenry are fulfilled. They also need to 
ensure that the applied safety standards are appropriate for the unique 
environment in which gas distribution occurs. Distribution pipeline 
systems are limited in geographic scope, although some systems serve 
many thousands of customers. The environment in which they operate 
significantly affects the safety issues that they face. Factors such as 
weather (dry/wet, hot/subject to freezing), soil conditions 
(corrosivity), and the local economy (significant construction and 
excavation activity) can significantly shape the threats affecting 
individual distribution operators and the actions necessary to address 
those threats. Proximity to gas-producing regions also can be 
important, as natural gas that is distributed near production areas may 
be subject to less processing and may contain more contaminants, with 
greater potential to affect system integrity, than gas that is 
processed for long-distance transportation.
    States must have flexibility to deal with their local 
circumstances. It would be both ineffective and inefficient, for 
example, to impose frost heave damage requirements in the desert 
southwest. States address these differences by imposing some 
requirements that exceed those in the Federal safety code.
    The National Association of Pipeline Safety Representatives 
(NAPSR)\2\ surveyed its members to determine the extent to which they 
impose requirements or programs that exceed the Federal minimum.\3\ The 
survey, addressed to each State pipeline safety program manager, asked 
whether the State imposes additional requirements or has infrastructure 
safety improvement programs implemented that exceed the federal minimum 
requirements. NAPSR asked its members to provide a brief description of 
any positive responses.
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    \2\ NAPSR's members are the managers of the pipeline safety 
regulatory staff from each state (and the District of Columbia) that 
is certified by, or a designated agent of, DOT for regulatory 
oversight.
    \3\ NAPSR conducted the survey in 2004-2005.
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    Forty-eight State agencies and the District of Columbia responded 
to the NAPSR survey. All but six reported some requirements or programs 
exceeding the Federal minimum standards. The results were as follows:
     20 States have additional reporting requirements;

[[Page 36018]]

     11 States provide enhanced oversight and observation of 
work/testing on the pipelines;
     11 States have additional damage prevention requirements;
     13 States require additional leak testing;
     11 States impose leak response requirements (including 
eight of the 13 that require additional leak testing);
     Eight States impose either additional odorant requirements 
or more frequent testing;
     Six States impose additional design and installation 
requirements;
     Six States impose additional training and qualification of 
operator personnel requirements.
     Six States impose additional requirements related to 
cathodic protection systems used to protect steel pipe from corrosion;
     Six States require their State regulators to approve 
operators' operating and maintenance plans;
     Five States impose operating pressure requirements;
     Five States impose additional customer meter requirements;
     Three States require that operators cap off abandoned 
service lines after specified periods;
     Four States extend operator responsibility for maintenance 
of service/customer lines;
     Four States encourage safety enhancement through rate 
cases, and approve the operation of distribution pipeline systems by 
specific companies;
     One State requires its operators to conduct an annual 
evaluation of all cast iron and unprotected steel pipe in their 
distribution systems; and
     One State requires its operators to remediate any evidence 
found of corrosion within 90 days.
    The most significant area in which States reported actions beyond 
Federal standards was replacement of aging and inferior infrastructure. 
Thirty-three States, or two-thirds of those responding, reported they 
have some kind of program for replacing infrastructure, including cast-
iron pipe, uncoated steel pipe, copper pipe, and some types of plastic 
pipe. These programs varied in scope and schedule, often reflecting the 
relative amount of targeted infrastructure present in each State. NAPSR 
collected the following data on pipe replacement programs:
     Twelve States reported their programs involved all (or 
nearly all) operators;
     Sixteen States reported their programs involved one or a 
limited number of operators, often in response to past accidents or 
rate cases;
     Four States provided no information from which to estimate 
the scope of their programs;
     Eight States reported that their programs are complete 
(i.e., all targeted infrastructure has been replaced) or will be 
completed by 2010;
     Eight States reported that their programs will be complete 
by about 2020;
     Four States reported that their programs would not be 
complete until after 2020; and
     Twelve States did not report an expected completion date.
These results indicate States can and do exercise authority beyond 
minimum Federal requirements. Additional requirements are focused in 
scope, and vary from State to State, based on local needs and issues. 
Programs to replace older, inferior infrastructure are the most 
widespread practice beyond Federal requirements. Such programs are in 
progress in two-thirds of the States, although some of these programs 
are of limited scope (i.e., affecting a single operator).
    Still, despite these State efforts, serious incidents continue to 
occur on distribution pipeline systems. As discussed above, the number 
of serious incidents per mile is similar to that for gas transmission 
pipelines, but there are many more miles of distribution pipelines. As 
a result, serious incidents on gas distribution pipelines kill or 
injure more people annually than do incidents on gas transmission 
pipelines. Even if the number of serious incidents on transmission 
pipelines is significantly reduced, major improvement in overall safety 
will not be achieved unless the number of incidents on distribution 
pipelines is also reduced. PHMSA's approach to achieving improvement 
for gas transmission pipelines was to require that each operator 
analyze its own pipeline's risks, through an integrity management 
program, and address them as necessary. PHMSA concludes that the same 
approach is appropriate for distribution pipelines.
    Although the additional State requirements provide protection 
beyond the minimum Federal standards to help assure the integrity of 
distribution pipeline systems, the requirements vary by State. No State 
requires a comprehensive systematic evaluation and management of the 
risks associated with operating gas distribution pipelines similar to 
PHMSA's existing IM requirements or to the requirements we are 
proposing in this Notice. Nevertheless, some State imposed requirements 
likely encompass individual actions operators would be required to take 
under an IM program, offsetting the costs for those operators to comply 
with this rule.
    The National Association of Regulatory Utility Commissioners 
(NARUC) has also considered the need for additional safety regulation. 
NARUC members represent Public Service/Safety Commissions under whose 
auspices States usually conduct pipeline safety regulatory programs. As 
such, NARUC represents executive management of State pipeline safety 
programs. In February 2005, the NARUC Board of Directors adopted a 
resolution encouraging development of an approach to distribution IM 
using risk-based, technically-sound, and cost-effective performance-
based measures. NARUC recommended an approach based on the notion that 
operators are knowledgeable about their infrastructure and can identify 
and respond to threats against their systems in order to reduce the 
risk of system failures while balancing the need to ensure continued 
safe, reliable service at a minimal financial cost.
    NARUC based its resolution on the long-standing commitment of 
industry and government to operate the United States' gas pipeline 
system reliably and safely. They acknowledged recent examinations by 
regulators, legislators, and gas distribution pipeline operators to 
determine the most effective approach to maintaining and enhancing 
distribution system integrity and safety. NARUC commented that States 
must take into account varying circumstances including: geography, 
energy customer base, local economy, system age and construction 
materials, size of distribution operations and consumption patterns of 
gas customers (ranging from large-volume manufacturers to mid-size 
businesses to single-family residences), as well as a State's overall 
executive policies and goals.
    NARUC noted that due to significant structural, geographical, and 
functional differences among gas transmission and distribution 
companies, it would be infeasible to apply many transmission integrity 
requirements to distribution systems. NARUC further noted any 
adjustment to an operator's distribution IM program should be 
responsive to the operator's safety performance, existing regulations, 
and current practices affecting such performance.

E. Applicability of Integrity Management Plans (IMP) to Distribution 
Pipeline Systems

    The basic premise of the integrity management programs for gas 
transmission and hazardous liquid

[[Page 36019]]

pipelines--that safety is improved by identifying risks and taking 
actions to address them--is applicable to distribution pipeline 
systems. However, because of the differences between distribution 
pipeline systems and pipeline systems covered by current IM 
regulations, the physical inspections (e.g. In-Line Inspection tools 
and Direct Assessment methods) of pipeline segments required by the 
current IM regulations cannot be required on distribution pipelines. 
Because the same IM regulations will not work, a different type of 
integrity management approach is necessary.
Distribution Systems Are Located in Highly Populated Areas
    The first element of existing IM program requirements for 
transmission pipelines is to identify so-called ``high consequence 
areas''--those segments of the pipeline where an incident/break could 
produce serious harm to people or the environment. This is important 
for hazardous liquid and gas transmission pipelines because both 
traverse large distances, including areas that are sparsely populated 
or where risk of serious environmental damage would be small. 
Identifying high consequence areas improves the effectiveness of 
integrity management requirements by focusing inspection and assessment 
efforts on the pipe where significant consequences could occur.
    As described above, gas distribution pipeline systems are 
different. Unlike transmission pipelines, they do not traverse long 
distances and generally do not include significant areas of limited 
population. They operate almost entirely in populated areas, because 
their purpose is to provide gas service to the residences and 
businesses of those populations. Thus, by contrast to a transmission 
pipeline, identifying areas where the gas distribution pipeline is near 
concentrations of people would not tend to identify a limited portion 
of the pipeline on which integrity management attention should be 
focused. Some other means of prioritizing operator attention, based on 
risk, is needed for distribution pipelines.
Challenges of Assessment or Testing
    As described above, distribution pipeline systems consist of a 
complex network of mains and services. They include considerable 
lengths of pipeline of very small diameter and many non-metallic 
materials. They also include extensive branching, with a typical city 
main being connected to a new service roughly every one hundred feet. 
These differences make it impossible to use many of the techniques 
required by the existing IMP regulations to assess the physical 
condition of the pipeline. One technique (in-line inspection) involves 
passing through the inside of a pipeline inspection tools that use 
magnetic detection techniques to identify areas where the wall of a 
steel pipe has been thinned by corrosion or damage. Another (direct 
assessment) involves using indirect inspection tools to identify areas 
where the electrical current imposed on steel pipes to prevent 
corrosion is interrupted or is experiencing interference. Distribution 
pipelines are too small and have too many connections to allow in-line 
inspection tools to pass through the lines, and approximately half of 
the distribution pipeline system is non-metallic (e.g., plastic), 
meaning that neither the internal tools nor the indirect inspections 
used for direct assessment can be used. Pressure testing (isolating a 
pipe and filling it with water or air at high pressure to see if it 
leaks) can be used, but would require that service be cut off to all 
customers served by the portion of the system being tested. A 
continuing program of such testing would essentially constitute the 
natural gas equivalent of ``rolling blackouts'' and would be 
unacceptable to the American public. Distribution pipelines can be 
inspected by digging to expose the pipeline, and operators are required 
to do such inspections when pipe must be excavated for other reasons. 
Digging up all distribution pipelines on a periodic basis, however, is 
clearly impractical.
    For these reasons, the inspection requirements of current IMP 
regulations cannot be used for distribution pipelines.
    Some other approach is needed. As described below, PHMSA worked 
with stakeholder groups and held two public meetings to help determine 
how best to apply IMP principles in the gas distribution pipeline 
environment.\4\ These public meetings are discussed further below.
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    \4\ The public meetings concerning integrity management 
requirements were held on December 16, 2004 and September 21, 2005. 
A third meeting, on June 17, 2005, focused exclusively on 
appropriate requirements for excess flow valves. Summaries of all 
meetings are in the docket.
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II. American Gas Foundation Study

    The gas distribution industry recognized the need to consider its 
safety record and to determine if additional actions are needed. In 
late 2003, the American Gas Foundation (AGF) launched a study of the 
safety performance and integrity of gas distribution pipeline systems. 
Currently, operators must report an incident to PHMSA if it meets the 
reporting criteria in 49 CFR Part 191. The AGF study examined the 
record of incidents reported to PHMSA on gas distribution pipeline 
systems from 1990 through 2002 (the latest year for which data were 
complete at the time the study began) and compared that record to 
incidents reported for transmission pipelines over the same period.
    The AGF study analyzed trends in reported incidents and focused 
specifically on incidents involving deaths or injuries requiring 
hospitalization (called ``serious incidents'' in the study). A joint 
team, the Distribution Infrastructure Government-Industry Team (DIGIT), 
was established to oversee the AGF study. This team consisted of 
representatives of the AGF, the American Public Gas Association, and 
State pipeline safety regulators. PHMSA took part in DIGIT as an 
observer.
    The AGF published its findings in January 2005.\5\ The AGF study 
found a downward trend in serious incidents over the 13-year period 
analyzed at a 95 percent statistical confidence level. (No 
statistically significant trend was found when considering all reported 
incidents.) The number of serious incidents per 100,000 miles of 
distribution pipeline was essentially the same as that for gas 
transmission pipelines over the analyzed period. There are many more 
miles of distribution pipelines, however. Historically, distribution 
pipeline incidents result in more deaths and injuries than incidents on 
gas transmission or hazardous liquid pipelines, largely because 
distribution lines are located in populated areas and constitute a much 
larger share of the mileage of working pipelines.
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    \5\ American Gas Foundation, ``Safety Performance and Integrity 
of the Natural Gas Distribution Infrastructure,'' January 2005, 
available at https://www.aga.org/Template.cfm/Section=Non-AGA_
Studies_Forecasts_Stats&template.
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    AGF found the primary cause of serious incidents was outside force 
damage, principally third-party excavation. Outside force damage 
represented 47 percent of serious incidents over the analyzed period. 
Corrosion caused 6.5 percent of serious incidents, and all other causes 
contributed less than 10 percent each.
    AGF also examined practices gas distribution operators use to 
address threats to their systems, both those required by regulation and 
those performed voluntarily. The study found no obvious gaps and that 
industry practices exist to address known threats. Further, the study 
concluded (as for

[[Page 36020]]

hazardous liquid pipelines and gas transmission pipelines) serious 
incidents continue to occur (albeit rarely) despite compliance with 
existing regulations.

III Recommendations or Mandates of Oversight Bodies

A. DOT Inspector General

    In a report published June 14, 2004,\6\ the DOT's Inspector General 
(IG) found that recent accident trends for gas distribution pipelines 
are not favorable. The IG noted that nearly all of the natural gas 
distribution pipelines are located in highly-populated areas, such as 
business districts and residential communities, where a rupture could 
have the most significant consequences. As a result, the audit pointed 
out for the 10-year period from 1994 through 2003, accidents on natural 
gas distribution pipelines have resulted in more fatalities and 
injuries than accidents on hazardous liquid and natural gas 
transmission lines combined.
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    \6\ Audit report SC-2004-064, issued June 14, 2004.
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    The IG also recognized that applying risk management principles to 
distribution pipelines could help reverse these trends. In testimony 
before Congress in July 2004,\7\ the IG recommended that PHMSA should 
define an approach for requiring operators of distribution pipeline 
systems to implement some form of integrity management or enhanced 
safety program with elements similar to those required in hazardous 
liquid and gas transmission pipeline integrity management programs.
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    \7\ Id.
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B. National Transportation Safety Board

    The National Transportation Safety Board (NTSB) investigates 
serious pipeline accidents, including those that occur on gas 
distribution pipeline systems. Over the years, the NTSB has made 
several recommendations to improve safety regulation of gas 
distribution pipelines. In particular, the NTSB has recommended the use 
of excess flow valves (EFVs) in all new construction and replaced 
service pipelines.
    EFVs have received significant attention as a mitigation option for 
gas distribution systems. Current Federal regulations require that 
operators notify service line customers for new and replaced service 
lines of the availability and potential safety benefits of installing 
EFVs.\8\ In lieu of this notification, operators may elect to install 
the valves voluntarily when certain conditions apply. The valves are 
generally applicable for new installations or complete service piping 
replacement for single-family residential homes, where the operating 
pressure is greater than 10 pounds per square inch (psi). Operators 
must install the valve if the customer agrees to pay for the cost of 
such installation. Discussions with operators indicate that 
approximately 30% of distribution system operators are installing the 
valves as a routine part of new and replaced service installations in 
situations in which they apply. Many of these are larger distribution 
operators, so the percentage of new and replaced service line 
installations voluntarily including EFVs is higher.
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    \8\ 49 CFR 192.383.
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    PHMSA conducted additional studies on the effectiveness of the 
valves and on the experience that has been gained as a result of their 
use. NAPSR assisted in these studies. PHMSA concluded that EFVs, if 
specified and installed correctly, operate reliably to cut off the 
supply of gas in the event of major damage to the downstream service 
line (e.g., excavation damage). While performance problems had occurred 
with early installation of EFVs, the data also show that the valves 
seldom now suffer false activations, cutting off the supply of gas when 
no damage has occurred.
    EFVs installed in new construction or replaced service lines would 
mitigate an incident occurring on service lines in which the line was 
severed. The valves are designed to operate in the event of line 
ruptures that result in major flow of gas. At the same time, they are 
an inexpensive option for mitigating such incidents. The valves 
themselves cost less than $20 and the cost to install them, when a 
service line is being installed or replaced is nominal. They will not 
operate in the event of small leaks. They will not operate in the event 
of leaks or problems within a customer's residence or business, 
downstream of their pressure regulator, including situations in which a 
fire in a residence results in a breach of a gas appliance line in the 
residence.
    PHMSA asked Allegro Energy Consulting to review incident report 
records to estimate how many incidents might have been mitigated by the 
presence of an excess flow valve had one been installed at construction 
or during repair. Allegro reviewed 634 incident reports submitted 
between 1999 and 2003. They screened out those that did not involve 
service lines, that were obviously slow leaks, or which otherwise did 
not appear to meet the criteria as incidents for which an excess flow 
valve would be beneficial. As a result, Allegro identified 101 
incidents in which the presence of an EFV might have mitigated 
consequences over this five-year period. To be clear, this is an 
estimate. The incident reports do not include some information (e.g., 
gas flow rate) that is necessary to ascertain definitively whether an 
excess flow valve would have been effective. They do not include 
information on whether the 25% of fatalities or injuries in which 
automobiles struck gas meter set assemblies at the side of homes could 
have been prevented by an EFV shutting off gas flow.
    PHMSA also conducted a public meeting concerning EFVs, which is 
described in Section VI below.

C. Congressional Mandate

    Subsequent to the stakeholder groups' recommendations discussed 
below and the public meeting, Congress passed the Pipeline Inspection, 
Protection, Enforcement, and Safety Act of 2006 (PIPES Act), which the 
President signed into law in December 2006. The Act included a mandate 
that PHMSA require gas distribution operators to implement integrity 
management programs and to install EFVs in all new or replaced 
residential gas service lines where operating conditions are suitable 
for available valves, beginning June 1, 2008. This proposed rule 
includes requirements addressing this mandate, which will no longer 
require the customer notification requirements of Sec.  192.383. Thus, 
we are proposing to repeal this requirement.

IV. Stakeholder Groups

A. Stakeholder Groups' Involvement

    In 2004, as described above, the IG recommended that PHMSA 
establish IM requirements for distribution pipelines, including 
elements similar to those in the IM regulations for hazardous liquid 
and gas transmission pipelines (except for those related to physical 
inspection (i.e., assessment, of the pipeline). The IG highlighted this 
recommendation in testimony before Congress in 2004, and a report of 
the fiscal year (FY) 2005 Conference Committee on Appropriations 
required DOT to report its plans to establish such regulations. PHMSA 
filed its report in June 2005. A copy of the report is in the docket.
    PHMSA's report to Congress described the work of four stakeholder 
groups to investigate opportunities to enhance the safety of 
distribution pipelines. The four multi-stakeholder groups (viz. 
Excavation Damage Group, Data Group, Risk Control Practices Group and 
Strategic Operations Group), representing State regulators, the public, 
and the gas distribution industry,

[[Page 36021]]

collected and analyzed available information and issued a report of 
their investigations in December 2005. A copy of the report is in the 
docket. The groups agreed IM requirements for transmission pipelines 
could not be applied directly to distribution systems because gas 
distribution pipeline systems differ significantly from transmission 
pipelines in their design. The groups also found that diversity among 
gas distribution pipeline operators and systems was so great that 
prescriptive requirements suitable for all circumstances could not be 
established. Instead, the groups found it would be more appropriate to 
require all distribution pipeline operators, regardless of size, to 
implement an IM program, including seven key elements. These seven 
elements are described below under ``Stakeholder Group Findings.''
    The groups concluded that distribution IM requirements should apply 
to all distribution pipeline systems, rather than just to portions of 
systems in high-consequence areas. Distribution pipeline systems are 
located in populated areas, where incidents are likely to produce 
serious consequences. Because distribution pipelines operate at very 
low pressures, failures typically appear as leaks. Experience shows gas 
released through leaks can migrate underground and collect in nearby 
buildings or other locations. These leaks can result in fires and 
explosions in locations not directly on the pipeline. Thus, the method 
used to identify high consequence areas along transmission pipelines--
predicated on the likelihood that a fire or explosion would occur at 
the rupture location--would be irrelevant to gas distribution systems.
    The stakeholder groups generally concluded IM requirements for 
distribution pipelines should be established by a regulation that sets 
high-level performance objectives with implementation guidelines. This 
approach would allow States flexibility in implementing IM programs 
suited to their particular circumstances; operators flexibility in 
better identifying the sources of risk to their pipelines; and more 
focused actions aimed at addressing those risks.

B. Stakeholder Groups' Findings

    The stakeholder groups made the following findings and conclusions 
about the current state of gas distribution pipeline safety and 
integrity:
    1. Distribution pipeline safety and excavation damage prevention 
are intrinsically linked. Excavation damage poses, by far, the most 
significant threat to the safety and integrity of gas distribution 
pipeline systems. Therefore, excavation damage prevention presents the 
greatest opportunity for gas distribution system safety improvements. 
Any effort to improve distribution pipeline safety is flawed if it does 
not seriously address excavation damage prevention.
    2. The dominant cause of reportable distribution pipeline incidents 
is ``excavation damage,'' while ``other outside force'' and ``natural 
force'' are the second and third leading causes.
    3. Corrosion is the principal cause of distribution pipeline leaks 
removed for both mains and service lines, but it causes relatively few 
incidents.
    4. ``Excavation damage'' is nearly as significant as ``corrosion 
damage'' in causing service line leaks.
    5. Excavation damage and material/weld failures, respectively, are 
the second and third leading causes of leaks for both mains and service 
lines.
    6. Corrosion causes approximately four percent of incidents, 
indicating operators are managing corrosion to prevent it from becoming 
one of the major contributors to reportable incidents.
    7. The rate of reportable distribution incidents resulting in 
deaths and injuries has decreased from 1990 to 2002. (Note that the 
Inspector General's analysis and AGF study were conducted for different 
periods.)
    8. No statistically significant trend could be determined for total 
reportable distribution incidents for the same period.
    9. There is a downward trend for reportable incidents resulting in 
deaths or injuries caused by damage from outside force.
    10. Although not statistically analyzed, the data suggest a slight 
downward trend in corrosion-caused leaks, and a decreasing trend in 
leaks caused by third-party damage.

C. Stakeholder Conclusions

    Based on their findings, the groups concluded:
    1. The most useful option for imposing distribution IM requirements 
would be a high-level, flexible Federal regulation, with implementation 
guidance.
    2. Seven elements could describe the basic structure of a high-
level, flexible Federal regulation addressing distribution IM. Each 
operator would have to do the following regarding its pipeline system:
     Develop a written program describing management of the 
integrity of the distribution system;
     Have an understanding of the system, including the 
conditions and factors important to assessing risks;
     Identify threats applicable to the system, including 
potential future threats;
     Assess risks and characterize the relative significance of 
applicable threats to the system;
     Identify and put in place appropriate risk-control 
practices (or modify current risk-control practices) to prevent and 
mitigate risks from applicable threats consistent with the significance 
of these threats;
     Develop and monitor performance measures to evaluate 
effectiveness of programs, periodically evaluate program effectiveness, 
and adjust programs as needed to assure effectiveness; and
     Periodically report a select set of performance measures 
to jurisdictional regulatory authorities.
    3. Because a distribution IM program would cover the entire 
distribution system, there is no need to identify high-consequence 
areas.
    4. A distribution IM program should consider threats identified in 
the PHMSA Annual Distribution Report, PHMSA Form 7100.1-1, as ``Cause 
of Leaks'' in Part C:
     Corrosion;
     Natural Forces;
     Excavation Damage;
     Other Outside Force;
     Material or Welds (Construction);
     Equipment;
     Operations; and
     Other
    5. Distribution IM requirements should not exclude any class or 
group of local distribution companies.
    6. Operators may need guidance materials to comply with a high-
level, risk-based, flexible federal rule. Small operators may need more 
precise compliance guidance.
    7. Implementation of elements of distribution IM regulations should 
be based on information reasonably accessible to an operator and on 
information an operator can collect on a going-forward basis. 
Regulations should not require extensive research.
    8. The most useful performance measures at the national level could 
be incidents (per mile or per service), number of excavation damages 
per ``ticket,'' \9\ the status of implementing elements of the rule, 
the amount of pipe that is not state-of-the-art, and a redefined 
measure or measures related to leaks.
---------------------------------------------------------------------------

    \9\ A ticket is the information the underground facility 
operator receives from the one-call notification center.
---------------------------------------------------------------------------

    9. Operator-specific performance measures are unique and must match

[[Page 36022]]

the specific risk-control practices of its distribution IM program.
    10. The operator should periodically evaluate the effectiveness of 
its distribution IM program. Programs should specify the period for 
evaluating program effectiveness, which should be as frequently as 
needed to assure distribution system integrity.
    11. Operators should review and implement Common Ground Alliance 
(CGA) Best Practices, and other industry practices as appropriate, to 
reduce damages to their facilities. Similarly, other affected 
stakeholders should review and implement applicable CGA Best Practices.
    12. A joint stakeholder group formed to conduct an annual review of 
safety performance metrics data, to resolve issues, and to produce a 
national performance metrics report would be of considerable value.

D. Findings Relevant to Leak Management

    As described above, the stakeholder groups found that although 
corrosion is the dominant cause of leaks repaired on gas distribution 
pipeline systems, corrosion accounts for only four percent of gas 
distribution incidents. This reflects the importance and effectiveness 
of leak management practices operators currently use. The stakeholder 
groups agreed leak management is an important risk control practice and 
should be a part of a gas distribution IM program, along with 
excavation damage prevention.
    According to the stakeholder groups, the essential elements of an 
effective leak management program are as follows:
     Locate the leak;
     Evaluate its severity;
     Act appropriately to mitigate the leak;
     Keep records; and
     Self-assess to determine if additional actions are 
necessary to keep the system safe.
These elements are collectively referred to by the acronym LEAKS, 
representing the first letter of each element.

E. Stakeholder Considerations Regarding Excess Flow Valves

    The stakeholder groups devoted considerable attention to excess 
flow valves (EFVs) in the context of potential IM program requirements. 
As described above, an EFV is designed to stop the flow of gas in a 
service line experiencing major leakage, generally caused by excavation 
damage. The device prevents consequences associated with a significant 
escape of gas and its ignition. An EFV in a service line provides no 
protection for breaks downstream of the meter (in homes). Since 
pressure is reduced at the meter and the flow through, even a 
completely severed line in the home poses much less risk than if the 
same break were to occur on the higher-pressure service line upstream 
of the meter.
    The stakeholder groups considered the use of EFVs for IM and 
reached the following conclusions:
    1. Information drawn from surveys of State practices and 
operational experience for currently installed EFVs indicated:
     Over 6.3 million EFVs have been installed in the United 
States (i.e., protecting approximately 10% of all services).
     If correctly specified and installed, EFVs work as 
designed.
     EFVs will not work in all applications--for example, EFVs 
will not work in up to 60 percent of new services in Connecticut, a 
State favoring their use, because the service lines operate at 
pressures below that required for EFVs to function.
    2. Regulations should not require installation of EFVs on all new 
and replaced service lines. EFVs are one risk-control practice 
operators should consider along with others.
    3. Operators, as part of their distribution IM program, should 
consider the mitigative value of installing EFVs.
    In their findings, the stakeholder groups considered the NTSB's 
recommendation that DOT require installation of EFVs on all new and 
replaced gas service lines where operating pressure exceeds 10 
psig.\10\ This recommendation resulted from the NTSB's investigation of 
a 1998 accident in South Riding, Virginia, which destroyed a new home 
and killed one of its occupants.\11\ The NTSB concluded the accident 
was caused by gas escaping from a hole in the gas service line and the 
flow through that hole was of sufficient magnitude that an EFV would 
have prevented the accident.
---------------------------------------------------------------------------

    \10\ NTSB, ``Natural Gas Explosion and Fire at South Riding 
Virginia, July 7, 1998,'' Pipeline Accident Report PAR-01/01, June 
12, 2001.
    \11\ Ibid.
---------------------------------------------------------------------------

Comments From Fire Service Organizations
    The stakeholders also considered comments from representatives of 
the fire service organizations. The International Association of Fire 
Chiefs and the International Association of Fire Fighters wrote to the 
Secretary of Transportation in early 2004 urging DOT to require 
installation of EFVs. The organizations commented that fire fighters 
are often first to respond to incidents involving fires fueled by 
escaping gas and their lives were at risk in doing so. The same 
organizations, along with the National Volunteer Fire Council and the 
Congressional Fire Services Institute, wrote to PHMSA again in 2005 
after reviewing draft reports of the Risk Control Practices stakeholder 
group. The fire service organizations reiterated their recommendation 
about mandatory EFV installation and disagreed with the group's 
conclusion that EFVs should be treated under distribution IM 
requirements as one of the available mitigation options.
    (Note that the conclusions of the stakeholder groups are reported 
here for completeness, but that many have been rendered moot by the 
statutory mandate, enacted after the stakeholder group deliberations, 
that installation of EFVs be made mandatory)
Surveys
    In conjunction with stakeholder group findings, PHMSA considered 
the results of several surveys evaluating the prevalence and efficacy 
of EFVs in gas distribution systems. One survey, conducted by the 
National Regulatory Research Institute (NRRI), a university-based 
research arm of the National Association of Regulatory Utility 
Commissioners (NARUC), surveyed State regulatory commissioners, partly 
in response to PHMSA's interest in the subject. A second survey 
conducted by the National Association of Pipeline Safety 
Representatives (NAPSR) \12\ obtained results from pipeline safety 
program managers in all States (and the District of Columbia) with 
regulatory jurisdiction over distribution pipeline safety. A third 
survey, sponsored by PHMSA and conducted by Oak Ridge National 
Laboratory, examined in more detail the experience of nine gas 
distribution operators, some of whom install EFVs voluntarily and 
others who install in conformance with the requirements of 49 CFR 
192.383. Results of all three surveys are available in the docket for 
this rulemaking.
---------------------------------------------------------------------------

    \12\ NAPSR is an organization consisting of the state pipeline 
safety program manager from each state that exercises jurisdiction 
over pipeline safety.
---------------------------------------------------------------------------

    The surveys indicate EFVs, if correctly sized and installed, 
operate reliably. Instances of false closure, where gas flow stops even 
though the service line is undamaged, rarely occur. Likewise, the 
valves function reliably when service lines are damaged. In fact, one 
potential problem with EFVs --the increased risk that excavation-
related

[[Page 36023]]

damage will go unreported--is directly related to their effectiveness 
in stopping the flow of gas from a severed gas line. In some cases, 
particularly where directional boring \13\ is used, excavators may not 
even 0be aware they have damaged a gas service line. When an excavator 
damages a service line not protected by an EFV, gas is released and the 
excavator must stop work and notify the gas distributor to protect the 
safety of its own personnel and the house at which they are working. If 
an EFV is installed, the EFV functions to stop the flow of gas, and an 
irresponsible excavator can finish its work, re-fill the hole, and 
leave the site. Only later, when the residents discover they have no 
gas service, is the damage reported. The gas distribution operator must 
then re-excavate to locate and repair the damage, increasing the 
expense of the repair. Although anecdotal evidence shows excavators do 
not always notify operators of damage to service lines, PHMSA does not 
have the data to determine if this is a prevalent problem.
---------------------------------------------------------------------------

    \13\ Underground utilities are usually installed by digging a 
trench, laying the pipe or cable in the trench and refilling it. In 
such installations, damage to other utilities would be obvious. 
Directional boring is a technique used when trenching is 
impractical, often when utilities must be installed below paved 
surfaces. When directional boring is used, a service line could be 
damaged or severed. If an installed EFV operates properly to shut 
off the flow of gas, the installer may not even be aware that a gas 
service line has been damaged.
---------------------------------------------------------------------------

V. Public Meetings

A. Public Meetings Concerning Distribution Integrity Management

    PHMSA conducted two public meetings to collect and evaluate public 
comments on the potential for adding IMP requirements for distribution 
pipelines. During the first meeting, held December 16, 2004, 
presentations were made concerning the then-draft AGF study discussed 
above and the DOT IG's recommendation. Comments made at this meeting 
resulted in the stakeholder group investigations, which are discussed 
in section VI.
    The second public meeting, held on September 21, 2005, included 
presentations describing the stakeholder group investigations, which 
were then in progress. Participants included representatives of 
industry, State regulators, PHMSA, and the public, including persons 
involved in the stakeholder investigations. Key points made by meeting 
participants included the following:
     There must be a balance among improved safety, 
reliability, and costs. For municipal operators, cost trade-off 
involves potential effects on other community services, including 
public safety.
     The primary cause of incidents on distribution systems is 
outside force damage, and any action must address this threat. 
Operators have limited ability to prevent excavation damage, and 
excavators are not typically under the jurisdiction of pipeline safety 
authorities. Comprehensive damage prevention programs can reduce 
incidence of excavation damage.
     Leak management is an important element in assuring the 
integrity of gas distribution pipelines.
     The majority of companies affected by any new distribution 
IM requirements are small companies, and the needs of those operators 
differ from larger companies. Smaller companies will likely require 
more detailed guidance for implementing new rules.
    Summaries of both public meetings are in the docket.

B. EFV Public Meeting

    On June 17, 2005, PHMSA conducted a public meeting to discuss EFV 
performance, notification, and installation issues. The meeting 
included panel discussions involving members of industry, State 
governments, fire service organizations, the National Association of 
Fire Protection, advocacy groups, the NTSB, and researchers who 
analyzed EFV performance.
    Industry participants included representatives of companies 
voluntarily installing EFVs and those installing only when a customer 
requested. These company representatives said they analyzed the costs 
and benefits of installing EFVs under local conditions in deciding 
whether to install EFVs. Factors in these analyses include the size and 
growth rate of company service areas, costs of maintaining records 
related to notifications, experience with load growth after initial 
installation (which can result in a need to replace EFVs), and the 
relative effectiveness of alternative actions to reduce the threat of 
excavation damage. Operators also noted they have experienced instances 
in which excavators damaged a line equipped with an EFV, but the damage 
was not reported to the operator, increasing operator costs to repair 
the damage.
    PHMSA and Allegro Energy described PHMSA-sponsored research on EFV 
performance (discussed above). The research examined incidents reported 
on gas distribution systems over a five-year period (634 events)--the 
Allegro Energy analysis described above. The PHMSA study examined these 
narratives and concluded EFVs could have been a factor in mitigating 
101 (approximately 16 percent) of the analyzed incidents.
    The NTSB reported that serious accidents on gas distribution 
systems prompted its recommendation that PHMSA require EFV 
installation. Recognizing that States conduct most regulatory oversight 
of distribution operators, the NTSB contacted all State governors in 
1996, recommending they establish requirements for mandatory 
installation,. The responses to those recommendations--indicating 
States look to PHMSA for safety standards--reinforced the NTSB's 
support for a Federal requirement.
    Representatives of State pipeline safety authorities, utility 
commissioners, and regulatory program managers described the factors 
considered by States in evaluating EFVs. They said local conditions 
could affect decisions on whether to use the valves. Initial 
installation costs are small, but life-cycle costs must be considered. 
They reported that EFVs provide protection from a limited scope of 
incidents involving significant damage to, or severance of, a service 
line. Many operators reported their belief that their resources are 
better spent attempting to reduce the frequency of those events rather 
than on installing EFVs. While all agree damage reduction activities 
can improve safety for existing gas services, they believe retrofit 
installation of EFVs, where the service line is not being replaced for 
other reasons, is impractical.
    Public safety advocates expressed significant concern with the 
manner in which operators are implementing the notification 
requirements in 49 CFR Sec.  192.383. Often the ``customer'' notified 
about the availability of EFVs for newly installed services is a 
builder/developer rather than the resident of a home. Experience 
indicates few builders/developers elect to have EFVs installed. When 
homes are then occupied shortly after the gas service is installed, the 
customer neither enjoys the protection of an EFV nor has the 
opportunity to decide to pay for the added protection.
Comments From Fire Service Representatives
    Fire fighters participated in the stakeholder groups and public 
meetings. Because the consequences of accidents on gas distribution 
pipelines generally result from fires fed by escaping gas, fire 
fighters have a significant interest in reducing the frequency and 
consequences of such events.
    As described above, the International Association of Fire Chiefs, 
the

[[Page 36024]]

International Association of Fire Fighters, the National Volunteer Fire 
Council, and the Congressional Fire Services Institute support a 
requirement to install EFVs in all new and replaced service lines where 
installation is suitable. Additionally, these organizations support IM 
programs for gas distribution operators to identify and evaluate 
specific risks associated with their systems and to implement measures 
to minimize those risks. The organizations agreed most operators will 
need guidance to implement these requirements and small operators are 
likely to need guidance that is more precise. These organizations also 
believe it is vital for operators to implement strategies to reduce the 
frequency of outside force damage. The comments of these organizat