[Federal Register: June 25, 2008 (Volume 73, Number 123)]
[Proposed Rules]
[Page 36015-36034]
[DOCID:fr25jn08-45]

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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: http://www.regulations.gov. This site
allows the public to enter comments on any Federal Register notice
issued by any agency.
     Fax: 1-202-493-2251.
     Mail: DOT Docket Operations Facility (M-30), U.S.
Department of Transportation, West Building, 1200 New Jersey Avenue
SE., Washington, DC 20590.
     Hand Delivery: DOT Docket Operations Facility, U.S.
Department of Transportation, West Building, Room W12-140, 1200 New
Jersey Avenue SE., Washington, DC 20590 between 9 a.m. and 5 p.m.,
Monday through Friday, except Federal holidays.

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

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

Privacy Act Statement

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

FOR FURTHER INFORMATION CONTACT: Mike Israni at<PHONE_NUMBER> or by e-
mail at<EMAIL_ADDRESS>
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

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;

     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

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 http://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

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,

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

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

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

International Association of Fire Fighters, the National Volunteer Fire
Council, and the Congressional Fire Services Institute support a
requirement to install EFVs in all new and replaced service lines where
installation is suitable. Additionally, these organizations support IM
programs for gas distribution operators to identify and evaluate
specific risks associated with their systems and to implement measures
to minimize those risks. The organizations agreed most operators will
need guidance to implement these requirements and small operators are
likely to need guidance that is more precise. These organizations also
believe it is vital for operators to implement strategies to reduce the
frequency of outside force damage. The comments of these organizations
are in the report of the stakeholder group investigations and are in
the docket.
    Representatives of the National Association of State Fire Marshals
(NASFM) and the National Fire Protection Association (NFPA)
participated in stakeholder groups. State Fire Marshals are responsible
for overseeing compliance with State fire codes and related building
standards, training fire fighters, and other duties based on State
agency assignments. NFPA is a professional association responsible for
developing American National Standards Institute approved consensus
standards related to fire safety.
    NASFM also supports mandatory installation of EFVs. In comments
made at the June 2005 public meeting on EFVs and the September 2005
public meeting on distribution IM, NASFM also supported a comprehensive
approach to IM. This approach would address all threats, prioritize
them for action, and deal with them based on importance.
    NFPA also supports IM requirements for gas distribution pipelines
and agrees new requirements for distribution systems will primarily
affect smaller operators who will need detailed guidance to implement
them. NFPA acknowledges EFVs will reliably stop gas flow if the flow
exceeds their trip point, but cautions that the valves are not a
panacea because damage to a service line may not always result in
sufficient flow to trip an EFV.
    A complete summary of this meeting is available in the docket.

VI. Guidance for IM

    As described above, the stakeholder groups concluded operators
would need guidance to implement a regulation requiring operators to
meet high-level performance objectives to improve IM. The diversity
among distribution systems and the size/capabilities of distribution
operators make it impractical to require specific, detailed actions in
the regulation. In particular, the stakeholder groups described above
reported to PHMSA that operators need guidance to describe the
following:
    1. Information they should gather through routine activities to
improve their understanding of the distribution system infrastructure.
    2. How best to assemble detailed information on pipe
characteristics (including material, manufacturer, batch, etc.) to
strengthen their understanding of the system and to support current and
future risk-management activities.
    3. Threat evaluation processes and data needed to support this
evaluation.
    4. Options for evaluating the relative importance of threats.
    5. How to perform risk analysis, encompassing situations from
small, simple distribution systems to large and complicated ones, and
how to use the results of these analyses.
    6. Decision processes and criteria for choosing among prevention,
detection, and mitigation measures.
    7. Options for measuring safety program effectiveness and
determining the situations under which different measures would be
meaningful.
    8. How to evaluate the overall effectiveness of the program such as
how to determine if the program is being implemented as described and
how to determine if the program is producing improvements.
    9. How to structure a comprehensive leak management program, which
is fundamental to successful management of distribution risk. At a
minimum, operators need guidance to implement the LEAKS program or the
following:

--Determine how local conditions and system knowledge should affect the
frequency and type of leak surveys.
--Identify methods/criteria for evaluating the severity of leaks and
need for action.
--Describe records an operator should maintain to permit trending and
identification of underlying problems.
--Identify performance metrics and the types of analyses in which the
operator should consider them.

    On March 2, 2006, PHMSA asked the Gas Piping Technology Committee
(GPTC), a standards-developing body, to prepare guidance. GPTC is
accredited by the American National Standards Institute (ANSI), the
governing body for consensus standards development in the U.S. GPTC has
historically prepared guidance to assist operators in implementing
various parts of natural gas pipeline safety regulations in 49 CFR Part
192. GPTC agreed and formed a Distribution Integrity Guidance Task
Force to develop guidance. The GPTC guidance will provide suggestions
for operators concerning options they could use to implement the high-
level requirements in a final rule. The GPTC will describe the scope
and content of the guidance at a public meeting during the comment
period.
    The GPTC guidance is designed to assist operators in developing
their distribution integrity management programs. PHMSA expects the
guidance will provide options that operators can use to implement the
DIMP requirements and that inspectors, primarily from State pipeline
safety agencies, also will use the guidance as examples of actions an
operator could take to comply with the rule. It will be up to each
operator to develop its plan implementing the DIMP requirements. The
GPTC guidance is only intended to assist operators; operators may use
other approaches. Whatever approach and guidance an operator uses to
develop its plan, it will be up to the operator to demonstrate how its
approach satisfies the DIMP requirements. When inspectors identify
deficiencies in operator plans and procedures intended to satisfy the
requirements, they will use existing enforcement tools, based on non-
compliance with the rule (not with the guidance) to cause operators to
comply. PHMSA is not proposing to incorporate by reference the GPTC
guidance.
    PHMSA understands the GPTC guidance will be published for public
comment, as part of the ANSI approval process, after this NPRM is
published.
    PHMSA also is supporting work by the American Public Gas
Association (APGA) Security and Integrity Foundation (SIF) to develop
more specific guidance for use by the smallest operators. These are
usually municipalities that have limited resources to develop IM
programs. SIF is a non-profit 501(c)(3) corporation, which was
established by the APGA in 2004. The SIF is dedicated to promoting the
security and operational integrity and safety of small natural gas
distribution and utilization facilities. The SIF will focus its
resources on enhancing the abilities of gas utility operators to
prevent, mitigate and repair damage to the nation's small gas
distribution infrastructure. In this work, SIF is using the GPTC
guidance to develop a computer program that will assist small operators
in developing their IM programs.
    PHMSA and NAPSR have formed a joint workgroup to develop a
framework

for oversight of the Federal requirements for the distribution
integrity management program. This joint workgroup is charged with
developing an oversight program that provides consistency in the
States' oversight of operator plans. The guidance developed by GPTC
will be key to this process. States have the responsibility for
designing and implementing their oversight programs, but PHMSA needs
certain information from these programs to evaluate the effectiveness
of the new Federal requirements, report results to Congress and
organizations that oversee us, and determine if future changes are
needed. PHMSA's goal in this workgroup is to provide regular reporting
on progress and results of inspections of distribution operators'
compliance with the final DIMP rule.

VII. Applicability to Small and Simple Distribution Systems; Request
for Comments

A. Master Meter and Liquefied Petroleum Gas (LPG) Operators

    We believe IM regulations for master meter and LPG operators should
be limited because these systems are simple and seem to pose relatively
little risk.
    By contrast to other local distribution systems, master meter
system operators receive gas at a single meter (the master meter) and
operate small pipeline systems to deliver the gas from the meter to a
small number of users. A typical example of a master meter operator is
a trailer park where the trailer park owner/operator receives gas from
a local distribution company and distributes it, via underground
piping, to individual trailer pads. Master meter pipeline systems tend
to cover limited geographical areas. They are simple systems, often
including only one type of pipe, operating at a single pressure, and
having no equipment other than pipe, meters, service pressure
regulators, and valves.
    Master meter operators are subject to the requirements of Parts 191
and 192, but some requirements are modified to better suit these
simpler systems. For example, master meter operators must have damage
prevention plans under Sec.  192.614, but their plans do not have to be
written. Similarly, these operators must provide notification of
incidents by telephone (Sec.  191.5) but do not have to submit written
incident reports (Sec.  191.9) or annual reports (Sec.  191.11). These
modifications recognize these systems are generally simple and
represent less risk.
    LPG systems are small systems, mostly in rural areas, that use
liquefied petroleum gas to serve a number of customers, usually in
areas not served by natural gas transmission lines. Like master meter
pipeline systems, LPG systems are simple and tend to cover limited
geographical areas. Further, we estimate each master meter and LPG
system operator has, on average, 100 services at low pressure. Very
small operators with less than ten services and no portion of their
systems in public areas will not be subject to the requirements of this
proposed rule because these small operators are generally exempt from
Part 192.\14\
---------------------------------------------------------------------------

    \14\ Section 192.1(b)(6) states the requirements of Part 192 do
not apply to operators of ``any pipeline system that transports only
petroleum gas or petroleum gas/air mixtures to--(i) Fewer than 10
customers, if no portion of the system is located in a public
place.''
---------------------------------------------------------------------------

    PHMSA's review of reported incidents shows few incidents occur in
master meter and LPG systems. Because of the relative simplicity of
these pipeline systems, a risk analysis would provide much less useful
information than an analysis of a more complicated distribution system.
Master meter operators often exercise more positive control over
excavations near their pipelines, thereby providing enhanced protection
from third-party damage, the leading cause of distribution system
incidents.
    Based on this analysis and the distinctions that already exist in
the regulations, the proposed rule would limit the scope of the IM
requirements for master meter operators and LPG operators. Under the
proposal, these operators would not have to perform risk analyses as
part of their IM program because the relative simplicity of their
systems makes the effort to perform the analysis more burdensome than
beneficial. Additionally, these operators will not have to report
performance measures, although they will need to maintain internal
records of performance for inspection purposes.
    PHMSA invites public comment on the following:
     Whether these IM limitations are appropriate for master
meter and LPG system operators;
     Whether we should further limit the IM requirements for
these operators; or
     Whether we should exempt these operators from IM
requirements.

B. Very Small Distribution Systems

    PHMSA notes there may be some local distribution systems of limited
area and simple design for which similar limited IM requirements may be
appropriate. There is currently no regulatory precedent for
differentiating among local distribution systems to identify a class of
operators to exempt from certain requirements. PHMSA would consider
limiting IM requirements for other operators of small, simple systems
if we can establish reasonable criteria to identify operators for which
such limitations are appropriate.
    PHMSA does not consider the number of customers an appropriate
selection criterion. Size, as measured by number of customers, is not
directly correlated to risk. For example, a system serving several
thousand customers that was installed over a brief period (e.g., after
a transmission line was installed nearby providing a source of gas)
could be quite uniform in design and materials. On the other hand, a
system serving a few hundred customers that has been installed
piecemeal over many years could have multiple types of material,
including older materials subjected to age-related degradation, etc. In
this example, the larger system would be expected to pose considerably
less risk than the smaller. Rather than the system's size, PHMSA
considers that appropriate criteria would identify systems with
characteristics similar to those of master meter systems and
representative of low risk. PHMSA proposes the following basis for
making this distinction:
    1. The system operates at a single pressure;
    2. The system may include valves, meters, and service pressure
regulators, but no other equipment;
    3. The physical environment (i.e., potential for corrosion) is
similar throughout the entire system;
    4. Most of the system was installed at one time, consisting of one
material. Additions may have been made later of another material, but
those additions are limited and their location is known; and
    5. The system location allows the operator to exercise control over
most third-party excavation.
    PHMSA invites comment on whether limited IM requirements should
also apply to operators of simple distribution pipeline systems and on
whether the above criteria would be appropriate for identifying systems
to which to apply this limitation.

VIII. Plastic Pipe Issues

A. Plastic Pipeline Database and Availability of Failure Information

    A significant amount of gas distribution pipeline is made of
plastic. Very little plastic pipe is used in other pipeline systems.
The Plastic Pipe Data Committee (PPDC), a voluntary group

consisting of representatives of industry, the NTSB, State pipeline
safety regulators and PHMSA, and administered by the American Gas
Association (AGA), monitors in-service performance of plastic pipe.
Participating operators send information on problems occurring with
plastic pipe and related fittings in their pipeline systems. PPDC
periodically analyzes this information to identify adverse performance
trends and problems potentially requiring action by plastic pipe users.
PPDC information has limited distribution and is generally not
available to operators who do not participate in the program. Gas
distribution pipeline operators whose systems include significant
amounts of plastic pipe would be better able to carry out an IM program
with knowledge of plastic pipe performance issues.
    PHMSA believes changes to the PPDC process could significantly
improve operator insight into the risks associated with plastic
distribution pipelines. In particular, more data of better quality and
improved availability of results from PPDC data analysis could help
inform operators of potential integrity issues related to their plastic
pipe. Changes PHMSA would consider valuable include the following:
     Changing the current system of data collection, analysis,
and communication to allow all operators better access to information
on ``suspect'' materials in their systems (once analysis identifies a
potential generic problem);
     Adding new requirements to facilitate operator use of PPDC
information; and
     Adding requirements for information gathering on existing
installed piping and equipment when normal operation and maintenance
exposes the pipe.
    PHMSA intends to discuss with AGA how to strengthen the PPDC
process and improve availability of results and to encourage AGA to
continue related discussions with PPDC members. PHMSA also invites
public comment as to whether the PPDC, administered by AGA, is
adequately objective to evaluate and report to the industry information
concerning plastic pipe failures, or whether PHMSA should seek a new
independent third party to perform this function.
    PPDC is an independent entity. PHMSA cannot dictate the actions
that PPDC takes. PPDC may not agree to changes that would provide
information to operators who do not participate, and who cannot now
include in their analyses failures that occur at non-participating
operators. Further, it is uncertain whether a different independent
third party can be identified that would be willing and able to assume
the task of analyzing failure information. Given the importance of
plastic pipe integrity to distribution pipeline system safety, PHMSA
has included in this proposed rule requirements for all operators to
report data on failures that occur in plastic pipe/fittings. We are
proposing that reports be made within 90 days of the occurrence of a
failure. PHMSA will collect the data and ensure that the data are
analyzed and that appropriate insights are communicated to all
distribution pipeline operators for their consideration as part of
their integrity management programs. PHMSA may take additional actions
if analysis of reported failures indicates additional regulatory action
is appropriate. PHMSA is proposing that a report be submitted within 90
days because we consider 90 days to be reasonable time for conducting
detailed failure cause analysis. PHMSA invites public comment on
whether some other reporting frequency is preferable and adequate to
identify trends (e.g., quarterly reporting, annual reporting).
    The proposed requirements to collect and report data on plastic
pipe failures from the final rule may not be necessary if another group
agrees to perform these functions. PHMSA invites comments on the
appropriateness of the proposed reporting requirements.

B. Plastic Pipe Marking

    Having better information on pipe type and its history would
improve operators' ability to manage their risk. In many cases, records
are inadequate to determine exactly what type of pipe is installed in
particular locations in distribution systems. It would be convenient if
pipe was marked so that operators could collect this information by
examining the pipe when it is excavated for other reasons.
Unfortunately, plastic pipe has not historically included any permanent
markings that would allow operators to determine the particular type of
plastic, its age, or other key parameters.
    PHMSA recognizes there are many technical issues associated with
pipe marking, and developing solutions requires discussion with all
affected organizations. Technical issues include the label contents,
durability, size, visibility, and spacing. PHMSA plans to discuss these
issues further with pipeline manufacturers, operators, AGA, and State
pipeline safety regulators. Thereafter, PHMSA plans to ask the American
Society of Testing and Materials (ASTM) to revise its current standard
for plastic pipe marking (i.e., ASTM D2513). PHMSA could then consider
incorporating the standards into federal regulations.
    PHMSA invites comments on the desirability of requiring permanent
markings on plastic pipe, on the related technical and logistical
issues, and on its proposed approach to rely on ASTM to establish
appropriate standards.

IX. Monitoring the Effectiveness of Actions

    It is important that any program intended to improve safety include
measurable attributes that can demonstrate whether the program is being
effective. The existing IMP requirements for hazardous liquid and gas
transmission pipelines both require operators to monitor performance
and to review their programs periodically to determine if there is a
need to change. This proposed rule contains similar requirements for
distribution pipeline system operators. Similarly, it is important for
PHMSA to be able to measure whether its actions are having the desired
effect--improved safety.
    The ultimate measure of distribution pipeline system safety is the
number of deaths and injuries and the amount of property damage caused
by incidents on distribution pipeline systems. Fortunately, however,
incidents occur relatively infrequently. The number of deaths and
injuries and the amount of damage are thus lagging indicators of
performance that cannot reliably capture safety trends other than over
long periods of time. Other interim measures are needed to provide
information in a shorter period to evaluate the effectiveness of any
new integrity management requirements implemented for distribution
pipeline systems. This proposed rule requires that distribution
pipeline operators submit to PHMSA annually the number of leaks
repaired (by cause), the number of excavation damages and the number of
``tickets'' (representative of the amount of excavation activity), and
the number of EFVs installed. PHMSA will use these data to evaluate the
effectiveness of new distribution integrity management requirements
until sufficient time has passed that trends in the overall number of
incidents, deaths, serious injuries, and property damage should be
apparent. PHMSA solicits comments on whether the paperwork burdens
associated with the collection of this data is justified by the
usefulness of this information. PHMSA also invites comment on other
measures that might be used to monitor effectiveness in this interim
period.

X. Deviating From Required Intervals Based on Operator's DIMP

    The underlying purpose of all of PHMSA's integrity management
requirements is to improve knowledge of the condition of each
operator's pipeline and to use that information to identify new risk
control solutions and to better focus risk reduction efforts. PHMSA
concludes, based on our experience with hazardous liquid and gas
transmission integrity management, that this process is working and is
producing a more efficient and effective approach to controlling
pipeline risk. PHMSA considers that implementing integrity management
for distribution pipelines should offer additional opportunities to
improve efficiency in assuring safety. Improving efficiency in assuring
safety requires, however, that it be possible to reduce efforts that
have marginal effect on controlling risk in order to shift resources to
more effective actions.
    As part of our continuing effort to improve efficiency and to make
the approach to pipeline safety more risk-based, we are proposing an
approach that would allow operators and the States to have more of a
role in setting compliance intervals for distribution operators within
a state. Rather than continue to require distribution operators to
comply with intervals set by existing federal regulation in Part 192,
this approach would let an operator use its distribution integrity
plan, and the risk assessment on which it is based, to propose
alternative intervals for Part 192 requirements that they must now
implement periodically.\15\ Operators could propose extended intervals
for threats and areas (e.g., portions of pipeline systems) where risk
is low, making the application of these requirements more risk-based.
---------------------------------------------------------------------------

    \15\ Operators are currently required to take the following
periodic actions:
    1. Cathodic Protection (CP) must be tested once per year.
Rectifiers and moving/active components must be inspected six times
per year (192.465)
    2. Operators must reevaluate pipelines without CP every 3 years
and provide CP if active corrosion is found (192.465)
    3. Pipe exposed to the atmosphere must be inspected for
corrosion every 3 years (Sec.  192.481)
    4. Leak surveys must be conducted annually in business districts
and at least every 5 years (3 if cathodically unprotected and
electrical surveys are impractical) outside of business districts
(Sec.  192.723)
    5. Pressure limiting devices must be tested at least annually
(Sec.  192.739)
    6. Each valve necessary for safe system operation must be tested
annually (Sec.  192.747)
    7. Vaults housing pressure regulating equipment must be
inspected annually (Sec.  192.749)
    8. Mains must be patrolled 4 times a year in business districts
and twice per year outside business districts (Sec.  192.721)
---------------------------------------------------------------------------

    Operators would be required to submit their proposed intervals to
the jurisdictional regulatory authority (usually the State) for review
and determination that the proposal will provide an adequate level of
pipeline safety. States would base their decisions on their review of
the operator's risk analysis and on their own knowledge of the safety
performance of, and issues affecting, each operator. While operators
would likely propose only longer intervals, States could exercise their
existing authority to impose requirements more restrictive than Federal
minimums to require shorter intervals where necessary based on risk.
PHMSA intends to work with NAPSR to develop guidance States can use in
making decisions concerning changes to the intervals for periodic
requirements.
    As an example, operators are now required to inspect pipelines
potentially subject to atmospheric corrosion, including service lines
entering customer gas meters, at least every three years. Many meters
are located inside homes where, in many cases, no one is available
during the day to provide access, and where the environment is unlikely
to be particularly corrosive. Operators must arrange with residents for
access, and must sometimes make multiple visits in order to complete
their inspections. The industry is seeking regulatory changes based on
these difficulties to reduce the frequency of required inspections of
inside meters. An alternative approach might be for operators to
establish that corrosion of pipelines in residences is low-risk, and to
propose an alternate interval for conducting these inspections. States
would have the flexibility to accept or modify operator adjustments to
these inspection intervals based on their local circumstances and their
understanding of operators' risk.
    We seek comment on the following issues:
     What are the advantages and disadvantages of allowing
operators and States to set intervals for each distribution operator on
required activities using a risk-based approach driven by thorough
analysis of individual operator performance data?
     Should there be some limit on the amount by which an
operator can deviate from currently-prescribed intervals (e.g., no more
than twice the interval in the Federal regulation)?
     How would a State establish guidance for implementing such
a process?
     What additional performance data and analysis would be
required?
     What costs to the States would be associated with such a
process?
     What cost savings to operators could result from such
changes?
     On what basis should a State judge the operators'
engineering basis adequate?

XI. Prevention Through People

    Historically, PHMSA's pipeline integrity management programs have
focused on assuring the physical and structural soundness of the pipe.
This is a key element to the safe transportation of hazardous
materials, including transportation by pipeline. However, it is only
part of the safety picture. The role of people, including control
center operators, in preventing and reducing risk is another critical
component in managing the integrity of pipeline systems, including
distribution piping.
    The proposed IM program regulations include requirements for
operators to understand the threats affecting the integrity of their
systems and to implement appropriate actions to mitigate risks
associated with these threats. These include a first step towards
instituting a ``Prevention through People'' (PTP) program to address
human impacts on pipeline system integrity. Human impacts include both
errors contributing to events and intervention to prevent or mitigate
events. As part of considering the threat of inappropriate operation
(i.e., inappropriate actions by people), this proposed rule would have
operators evaluate the potential for human error, considering existing
regulatory programs (e.g. Operator Qualification, Drug and Alcohol
Testing, Damage Prevention, Public Education) , and any voluntary
supplemental programs the operator now implements, in preventing and
mitigating risk. An operator would be required to include in its
written IM program a separate section on ``Assuring Individual
Performance,'' in which they would identify risk management measures to
evaluate and manage the contribution of human error and intervention to
risk (e.g., changes to the role or expertise of people).
    Several existing regulations strengthen the effectiveness of the
role of people in managing safety. These include Damage Prevention
Program in Sec.  192.614, Public Awareness in Sec.  192.616,
Qualification of Pipeline Personnel in subpart N under Part 192, and
drug and alcohol testing in Part 199. The evaluation required by this
proposed rule would consider the effects of these programs, and a PTP
program would integrate these existing efforts and would address the
risks associated with human factors as

enumerated in Section 12 of the PIPES Act, as well as the opportunities
for people to mitigate risks. PHMSA is separately developing proposed
requirements for control room management, which would also become a
part of the PTP program and a consideration for integrity management of
distribution pipeline systems.
    A PTP program could include regulations and a system to identify
and communicate noteworthy best practices. Because human interaction
with gas distribution systems contributes to the risk these systems
pose, PHMSA believes a PTP effort has strong potential to reduce
distribution system risk. PHMSA invites public comment on the PTP
concept and on any other requirements that should be included in this
or a future IM program rulemaking.
    PHMSA also requests public comment on how operators are currently
addressing human factors, including fatigue, in their ongoing efforts
to manage the integrity of their distribution pipelines.

XII. Summary Description of Proposed Rule

    Over the past eight years, more than 1,000 incidents on
distribution pipelines have resulted in fatalities, serious injuries,
or major property damage. Excavation damage and other outside forces
caused most of these incidents. This proposal reduces system operating
risks and the probability of failure by requiring operators to
establish a documented, systematic approach to evaluating and managing
risks associated with their pipeline systems. In this NPRM, PHMSA
proposes to add a new subpart to the Federal pipeline safety
regulations to require gas distribution pipeline operators to develop
and implement IM programs covering the seven IM program elements
identified by PHMSA and representatives of States, industry, and the
public who participated in the stakeholder groups. The proposed rule
also implements the legislative direction that PHMSA prescribe minimum
standards for IM programs for distribution pipelines. As discussed
above, PHMSA requested GPTC to develop more detailed guidance to assist
distribution operators in implementing a new rule and States in
overseeing these requirements.
    The proposed regulation would require operators to develop and
implement written IM programs addressing the following elements:
     Knowledge of infrastructure;
     Identification of threats;
     Evaluation and prioritization of risks;
     Mitigation of risks;
     Measurement and monitoring of performance;
     Periodic evaluation and improvement; and
     Reporting of results.
    The proposed rule implements the legislative direction that PHMSA
require distribution pipeline operators to install an EFV in each
newly-installed or replaced service line serving a single-family
residence for which a suitable valve is commercially-available and
where conditions are suitable. Suitable conditions include:
     Operation continuously throughout the year at a pressure
not less than 10 psig;
     No history of liquids or contaminants in the gas flow
which would interfere with operation of the valve; and
     Where installation is not likely to cause a loss of
service to the residence; or
     Interfere with required operation and maintenance
activities.
    Any installation will have to comply with the performance standards
in Sec.  192.381. The proposed requirement to install EFVs will make it
unnecessary for operators to notify customers of EFV availability as
currently required by Sec.  192.383. Thus, this proposal would repeal
the customer notification requirement.
    Because of the significant diversity among distribution pipeline
operators and systems, the IM requirements in the proposed rule are
high-level and performance-based. The proposal specifies the required
program elements, but does not prescribe specific methods of
implementation. Prescriptive, how-to requirements would likely not fit
the circumstances of all operators. Still, PHMSA recognizes many
operators will want additional detail about actions they may take to
implement the performance-based regulatory requirements. This is the
reason PHMSA asked GPTC to develop guidance providing examples of
methods that satisfy the requirements. Also, as discussed earlier, the
APGA SIF intends to use the GPTC guidance to develop model IM programs
for its small municipal members.

XIII. Section-by-Section Analysis

    Section 192.383 Excess flow valve customer notification. This
section currently requires operators to notify customers about EFV
availability for installation and install an EFV if the customer so
requests and agrees to bear all associated costs. The proposed
requirements in this NPRM would require operators to install EFVs in
new or replaced service lines unless certain conditions preclude
installation. We are repealing this existing requirement because the
proposed new requirements render the notification requirements in this
section unnecessary.
    Section 192.1001 What do the regulations in this subpart cover?
These proposed rules will apply to all operators of gas distribution
systems subject to Part 192. The proposed rules would require each
operator of a distribution pipeline system to implement an IM program
with prescribed minimum requirements. Under the proposal, IM
requirements applicable to master meter operators and operators of
liquid propane gas (LPG) distribution systems will be much more limited
than those applicable to larger operators. For example, the proposal
would not require these operators to install EFVs and would not have
them evaluate and prioritize risks and report results.
    Section 192.1003 What definitions apply to this subpart? PHMSA
proposes to add a definition for the term ``damage'' as used in Sec.
192.1005.
    Section 192.1005 What must a gas distribution operator (other than
a master meter or LPG operator) do to implement this subpart? The
proposed rule would require gas distribution operators, other than
master meter or LPG distribution system operators (see Sec.  192.1015),
to develop a formal IM program with certain prescribed elements and to
implement their programs no later than 18 months after the final rule
becomes effective. The IM program is to manage and reduce the risks
associated with the operator's pipeline system.
    Section 192.1007 What are the required IM program elements? The
proposed rule defines the minimum elements each operator's IM program
must include. Master meter and LPG operators will include only some
elements in their programs. For gas distribution operators other than
master meter or LPG operators, the required program elements are as
follows:
    a. Knowledge of the system's infrastructure. To develop an IM
program, an operator must identify threats applicable to its pipeline
system and analyze the risks its pipeline system poses. Operators
cannot do this without understanding their pipeline systems. Generally,
the operator should know information such as location, material
composition, piping sizes, construction methods, date of installation,
soil conditions, pressure (operating and design), operating experience,
performance data, condition of the system, and any other
characteristics

that help identify the applicable threats and risks.
    An operator may not know some necessary information about its
infrastructure. In some cases, distribution systems include pipe
installed several decades ago, and reliable records may not exist to
provide complete information. In other cases, distribution systems have
grown by acquisition and merger, as multiple pipeline systems came
under common ownership. Complete records may not have been transferred
during these changes in ownership, again leading to gaps in the
knowledge an operator has about its pipeline system. This proposed rule
does not require operators to engage in extensive investigative
programs to uncover information, nor does it require operators to
conduct excavations for the sole purpose of revealing information about
buried pipe.
    An operator must assemble as complete an understanding of its
infrastructure as possible using information the operator has on hand
from ongoing design, operations, and maintenance activities. An
operator's IM program must identify what additional information the
operator needs to know about its infrastructure, and must provide for
gaining that additional knowledge over time through normal activities.
For example, situations in which buried pipe must be exposed for
maintenance or other purposes present an opportunity to collect data
about the pipe and its environment at very little or no additional
cost. An operator's IM program must provide for identification and use
of such opportunities to improve knowledge of the distribution system
infrastructure.
    b. Identify threats (existing and potential). Operators need to
evaluate their pipeline systems and the environments in which the
pipelines operate to identify specific threats the pipelines face and
to determine what are appropriate actions to manage the threats and
minimize the risk. Threats affecting pipeline systems are generally
grouped into broad categories. This proposed rule uses the same
categories as does the form operators use to report incidents occurring
on their distribution pipeline systems (Form PHMSA F 7100.1). Not all
threat categories are applicable to all pipelines. For example,
corrosion does not affect plastic pipe. Additionally, the categories
often represent a grouping of similar threats, not all of which may
affect a given pipeline. Although all buried metal pipe is generally
considered subject to potential external corrosion, not all pipeline
systems are subject to internal corrosion. Outside force may be an
applicable threat, but outside force from earthquake movement may or
may not be an issue. The proposed rule would require operators to
identify both existing threats and potential threats. For example,
outside force from landslide or earth movement may be a potential
threat to a distribution pipeline system servicing an expanding
community, even though currently, the pipeline system is not affected
by such problems.
    In considering the threat of inappropriate operation, operators
would be required to evaluate the effects that actions of its personnel
can have on pipeline safety.
    c. Evaluate and prioritize risk. Simply knowing what threats exist
is not sufficient to understand and manage risk posed to distribution
pipeline systems. Operators must determine the likelihood that a system
failure would be caused by any given threat. Therefore, the proposed
rule would require operators to evaluate each applicable threat and
estimate the risk to the pipeline. An operator may subdivide the system
into regions (areas within a distribution system consisting of mains,
services and other appurtenances) with similar characteristics and
reasonably consistent risk, and for which similar actions would be
effective in reducing risk.
    d. Identify and implement measures to address risks. Once the
relative risks are known, operators can take action to mitigate those
risks and thus improve safety. The specific actions appropriate for an
operator to take will vary depending on the applicable threats, their
prevalence, and the risks posed by a leak or failure on the operator's
pipeline.
    The proposed rule would require operators to identify and implement
appropriate risk reduction strategies. Under the proposal, operators
would be required to implement at least two risk reduction strategies--
an effective leak management program and an enhanced damage prevention
program. Since excavation damage is the leading cause of incidents on
gas distribution pipeline systems, having effective measures to
minimize the likelihood of such damage would be a valuable risk
reduction method. Low-pressure distribution pipelines tend to fail by
leaking, except in some cases of excavation damage. Leaking gas tends
to migrate and can accumulate in buildings and other confined areas
where fires and explosion can result. Leaks can be identified and
corrected before injury to people and property occurs. Distribution
pipeline operators typically have established leak management programs.
This is the reason, for example, why leaks resulting from corrosion
represent 36 percent of leaks repaired on distribution mains and 25
percent on service lines, while corrosion is the cause of less than
five percent of distribution pipeline incidents.\16\ An effective leak
management program is thus a valuable risk reduction strategy for all
distribution pipeline operators.
---------------------------------------------------------------------------

    \16\ Integrity Management for Gas Distribution, Report of Phase
1 Investigations, December 2005, Attachment 4, page 18. Based on
data reported to PHMSA by distribution pipeline operators for 2004.
---------------------------------------------------------------------------

    Each operator would be required to develop an IM program with a
separate section on ``Assuring Individual Performance'' to improve the
safety performance of its personnel. This is a first step towards
implementing an integrated approach to assuring PTP.
    e. Measure performance, monitor results, and evaluate
effectiveness. The proposed rule would require each operator to measure
its performance and report certain measures periodically to PHMSA and
State regulatory authorities. Only by measuring results can an operator
know if its risk reduction efforts are effective. As proposed,
operators would have to make changes to their programs to improve
effectiveness if performance measurement indicates improvement is
needed. Regulators will use the reported performance measures to
evaluate overall effectiveness in reducing risk from gas distribution
pipeline systems. Further changes to regulations or to oversight (e.g.,
frequency of inspections) may be appropriate depending on the data
analysis findings.
    f. Periodic Evaluation and Improvement. Operators would use
measured performance to determine whether further improvements are
needed and to make necessary changes in their IM programs. Operators
would have to evaluate their programs periodically. Operators should
determine how often these reviews are appropriate. For large, complex
systems, sufficient data and experience may be available to make annual
reviews meaningful. For small, simple systems, there may not be
sufficient information to make an annual review meaningful. Whatever
the size of the system, all operators will have to conduct a complete
program evaluation at least once every five years.
    g. Report results. The proposed rule would require each operator to
measure its performance and report certain measures periodically to
PHMSA and State regulatory authorities. The proposal would require
operators to

report four of the required performance measures each March to PHMSA as
part of the annual report required by Sec.  191.11. Combining this
reporting with the annual report already required will minimize the
additional burden on operators to provide this information. Operators
would also be required to report these four measures to the State
pipeline safety authority where the gas distribution pipeline is
located. Operators also would be required to retain records of the
remaining listed performance measures for ten years.
    Section 192.1009 What must an operator report when plastic pipeline
fails? Plastic pipe (including fittings, couplings, valves and joints)
forms a significant portion of many distribution pipeline systems.
Plastic pipe is used very little in other pipeline systems. Knowledge
of potential weaknesses in its plastic pipe is thus particularly
important for a distribution pipeline operator analyzing the risk from
its system. This section would require that operators report all
plastic pipe failures to PHMSA within 90 days after a failure. PHMSA
will collect this information and will assure that it is analyzed to
identify and communicate significant information about potential
vulnerabilities associated with plastic pipe. Distribution pipeline
operators will then be able to take this information into consideration
in their risk analyses.
    Section 192.1011 When must an Excess Flow Valve (EFV) be installed?
Gas distribution operators, except for master meter and LPG operators,
would be required to install an EFV in each new or replaced service
line installed for a single-family residence if a suitable valve is
commercially available and certain operating conditions are present for
the EFV to function. The required operating conditions are: the
operating pressure in the service line must be 10 psig or greater; the
gas stream must be free of contaminants and liquids potentially
interfering with valve operation; installation must not result in loss
of service to the residence; the presence of an EFV must not interfere
with required operation and maintenance activities; and the EFV must
meet the performance criteria listed in 49 CFR Sec.  192.381.
    Section 192.1013 How does an operator file a report with PHMSA?
This section describes where an operator is to send required reports.
PHMSA prefers electronic submissions.
    Section 192.1015 What records must an operator keep? The proposed
rule requires an operator to make a number of decisions and to perform
a number of analyses to determine and implement risk reduction methods
most appropriate to its distribution pipeline system. It is critical
that an operator retain knowledge of the basis for its decisions for
the operator to effectively implement and modify its IM program. The
proposed rule specifies the records an operator would have to keep to
serve this purpose. These records also will allow PHMSA (or the
applicable State oversight agency) to review the operator's analyses,
decisions, and actions to determine through inspections if they are
reasonable and comply with the proposed requirements.
    Section 192.1017 When may an operator deviate from required
periodic inspections of this part? Various provisions of Part 192
require all distribution pipeline operators to perform actions at
prescribed intervals. 49 CFR 192.481, for example, requires all
operators to perform atmospheric corrosion inspection at fixed three-
year intervals, without regard to system-specific risk factors. It is
likely that some of these actions could be performed at less frequent
intervals (based on lower risk) with no difference in safety outcomes.
The resources made available by reducing action intervals, where
appropriate, could be used to address more risk-significant problems.
Thus, deviating from intervals now specified in other sections of Part
192 could allow operators to be more risk-based in application of their
resources.
    This section would allow operators to use their risk analyses to
propose changes to the intervals for periodic requirements included in
other sections of Part 192. Operators would be required to submit their
proposals to jurisdictional safety regulators (usually States) for
review and determination that the proposal will assure an adequate
level of pipeline safety.
    Section 192.1019 What must a master meter or liquefied petroleum
gas (LPG) operator do to implement this subpart? This section specifies
the requirements master meter and LPG operators must meet. Gas
distribution systems operated by master meter and LPG operators are
subject to the requirements of Part 192, but these systems are
generally smaller and pose less risk than systems operated by other gas
distribution operators. Master meter and LPG systems cover a smaller
geographic area, over which the operator usually has more control. In
particular, the operator usually has more control over excavation
activity, which is the leading cause of damage to gas distribution
pipeline systems. To reflect these differences, we are proposing a more
limited and simpler set of IM program requirements for these operators.
They must develop and implement written IM programs containing the
elements required of other gas distribution operators, except an IM
program for a master meter or LPG operation need not include the
elements for evaluating and prioritizing risks and reporting results.
There will be no EFV installation requirements. Also, the level of
detail in these IM programs should be much less to reflect the relative
simplicity of these pipeline systems. In a separate guidance document,
we will provide a model IM program these operators may use. A draft of
this guidance is available in the docket to this rulemaking. We request
comment on this draft guidance.
    Guidance. To carry out the proposed requirements, operators will
have to make a number of reasonably complex decisions and analyses to
understand their systems, evaluate threats and risks, and implement
risk reduction methods. While it is impractical to specify a single
method for how operators should make these decisions/analyses, it is
possible to provide guidance concerning factors operators should
consider This document will provide guidance in carrying out several
requirements. PHMSA expects GPTC to develop more detailed guidance to
assist operators in implementing a final rule. Once the GPTC guidance
is available, PHMSA may modify the proposed guidance. This draft
guidance document is available in the docket to this rulemaking

XIV. Regulatory Analyses and Notices

A. Statutory/Legal Authority for This Rulemaking

    This notice of proposed rulemaking is published under the authority
of the Federal Pipeline Safety Law (49 U.S.C. 60101 et seq.). Section
60102 authorizes the Secretary of Transportation to issue regulations
governing design, installation, inspection, emergency plans and
procedures, testing, construction, extension, operation, replacement,
and maintenance of pipeline facilities. The proposed integrity
management program regulations are issued under this authority and
address the NTSB's and DOT Inspector General's recommendations. This
rulemaking also carries out the mandates regarding distribution
integrity management and excess flows valves under section 9 of the
Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006
(Pub. L. 109-468, Dec. 29, 2006).

B. Executive Order 12866 and DOT Regulatory Policies and Procedures

    DOT considers this an ``economically significant'' regulatory
action under section 3(f)(1) of Executive Order 12866 (58 FR 51735;
October 4, 1993). This NPRM is also significant under DOT's regulatory
policies and procedures (44 FR 11034; February 26, 1979). PHMSA
prepared a Draft Regulatory Evaluation for this NPRM and placed it in
the public docket.
    The proposed requirements would affect an estimated 9,291 natural
gas operators with a combined total of 1,138,000 miles of mains and
60,970,000 services. Of these operators, 201 are local gas utilities
with more than 12 thousand services, 1,090 are local gas utilities with
12 thousand or fewer services, and 8,000 are master meter and LPG
systems.
    The monetized benefits resulting from the proposed rule are
estimated to be $214 million per year. Those benefits include:
     Reductions in the consequences of reportable incidents;
     Reductions in the consequences of non-reportable
incidents;
     A reduction in the probability of a major catastrophic
incident;
     Reductions in lost natural gas;
     Reductions in emergency response costs;
     Reductions in evacuations;
     Reductions in dig-ins impacting non-gas underground
facilities; and
     Elimination of the existing EFV notification requirement.
    The costs of the proposed rule are estimated to be $155.1 million
in the first year and $104.1 million in each subsequent year. Those
costs cover:
     Development of an IMP;
     Implementation of the IMP;
     Mitigation of risks;
     Reporting to PHMSA and State Regulators;
     Recordkeeping; and
     Management of the IMP.
    The analysis finds that, for those costs and benefits that can be
quantified, the present value of net benefits are expected to be
between $1.5 billion and $2.8 billion over a fifty year period after
all of the requirements are implemented. Also significant is that the
proposed rule is expected to be cost-effective if it results in
eliminating only approximately 14.5 percent of the societal costs
associated with gas distribution systems.

C. Regulatory Flexibility Act

    Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.) PHMSA
must consider whether a rulemaking would have a significant effect on a
substantial number of small entities. The proposed IM program
requirements apply to gas distribution pipeline operators and require
operators of gas distribution pipelines to develop and implement IMPs
that will better assure the integrity of their pipeline systems.
    Many gas distribution pipeline operators meet the Small Business
Administration's small business definition of 500 or fewer employees
for natural gas distribution operators under North American Industry
Classification System (NAICS) 221210. PHMSA estimates that the proposed
rule will affect 9,007 small operators. These small operators can be
separated into two categories: (1) Local gas distribution utilities
with 12,000 or fewer services and (2) master meter and LPG systems.
PHMSA estimates there are 1,007 small operators among the local gas
distribution utilities with 12,000 or fewer services and 8,000 master
meter and LPG systems, all of which are small.
    Furthermore, PHMSA estimates the proposed rule will cost each local
gas utility with 12,000 or fewer services on average approximately
$40,000 in the first year and $17,000 in each subsequent year. PHMSA
also estimates that the proposed rule will cost master meter and LPG
systems on average approximately $3,000 in the first year and $1,000 in
each subsequent year. PHMSA does not have information on the operators'
revenues and cannot estimate the economic impact the costs will have.
The costs associated with the proposed rule may be significant for at
least some of the small entities. Therefore, PHMSA believes that the
proposed rule could result in a significant adverse economic impact for
some of the smallest affected entities. PHMSA invites comments on these
assumptions.
    PHMSA has tried to minimize costs for these small operators. As
mentioned earlier, small operators' IM programs will not have to
include the elements for evaluating and prioritizing risks and for
reporting results and there will be no EFV installation requirements.
PHMSA is also providing a manual for small operators to guide their
compliance with the proposed rule and PHMSA will continue to evaluate
alternative methods of compliance that reduce the burden on small
businesses while retaining an appropriate level of pipeline safety.
Additionally, industry is undertaking a number of initiatives that will
help small entities comply with the proposed rule, including the
preparation of guidance materials and a model IM program for
distribution pipeline operators.

D. Paperwork Reduction Act

    The Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.)
addresses the collection of information by the Federal government from
individuals, small businesses and State and local governments and seeks
to minimize the burdens such information collection requirements might
impose. A collection of information includes providing answers to
identical questions posed to, or identical reporting or record-keeping
requirements imposed on ten or more persons, other than agencies,
instrumentalities, or employees of the United States. In accordance
with the requirements of the Paperwork Reduction Act, agencies may not
conduct or sponsor, and the respondent is not required to respond to,
an information collection unless it displays a currently valid Office
of Management and Budget (OMB) control number. PHMSA is requesting
comment on a proposed information collection. PHMSA is also giving
notice that the proposed collection of information has been submitted
to OMB for review and approval.
    This NPRM proposes additional information collection requirements.
Those requirements result from affected natural gas distribution system
operators having to (1) prepare a distribution integrity management
program (DIMP); (2) document their DIMP procedures and processes; (3)
prepare periodic revisions to their IM programs; (4) keep records, and
(5) report periodically to PHMSA and the States. PHMSA evaluated the
NPRM, as required by the Paperwork Reduction Act of 1995 (44 U.S.C.
3507(d)), and believes the burden hours to industry resulting from the
NPRM will be 681,379 in the first year and 85,597 hours in each
subsequent year. Large and small operators will bear the largest share
of the information collection burden. Master meter and Liquid Petroleum
Gas system operators are estimated to require 20 hours each to comply
in the first year and to make brief (less than \1/4\ hour) updates to
the initial information in subsequent years.
    Pursuant to 44 U.S.C. 3506(c)(2)(B), PHMSA solicits comments
concerning: whether these information collection requirements are
necessary for PHMSA to properly perform its functions, including
whether the information has practical utility; the accuracy of PHMSA's
estimates of the burden of the information collection requirements; the
quality, utility, and clarity of the information to be collected; and
whether the burden of collecting information on those who are to

respond, including through the use of automated collection techniques
or other forms of information technology, may be minimized.

E. Executive Order 13084

    This NPRM has been analyzed under principles and criteria contained
in Executive Order 13084 (``Consultation and Coordination with Indian
Tribal Governments''). Because this NPRM does not significantly or
uniquely affect communities of Indian tribal governments and does not
impose substantial direct compliance costs, the funding and
consultation requirements of Executive Order 13084 do not apply.

F. Executive Order 13132

    PHMSA analyzed this NPRM under the principles and criteria
contained in Executive Order 13132 (Federalism). PHMSA issues pipeline
safety regulations applicable to interstate and intrastate pipelines.
The requirements in this proposed rule apply to operators of
distribution pipeline systems, primarily intrastate pipeline systems.
Under 49 U.S.C. 60105, PHMSA cedes authority to enforce safety
standards on intrastate pipeline facilities to a certified State
authority. Thus, State pipeline safety regulatory agencies will be the
primary enforcer of these safety requirements. Although some States
have additional requirements that address IM issues, no State requires
its distribution operators to have comprehensive IM programs similar to
what we are proposing. Under 49 U.S.C. 60107, PHMSA gives participating
States grant money to carry out their pipeline safety enforcement
programs. Although some States choose not to participate in the
pipeline safety grant program, every State has the option to
participate. This grant money is used to defray added safety program
costs incurred by enforcing the proposed requirements. We expect to
increase money available to help States.
    PHMSA has concluded this proposed rule does not propose any
regulation that: (1) Has substantial direct effects on States,
relationships between the national government and the States, or
distribution of power and responsibilities among various levels of
government; (2) imposes substantial direct compliance costs on States
and local governments; or (3) preempts State law. Therefore, the
consultation and funding requirements of Executive Order 13132 (64 FR
43255; August 10, 1999) do not apply.
    This proposed rule would serve to preempt any currently established
State requirements in this area. States would have the ability to
augment pipeline safety requirements for pipelines, but would not be
able to approve safety requirements less stringent than those contained
within this proposed rule.
    Although the consultation requirements do not apply, the States
have played an integral role in helping develop the proposed
requirements. State pipeline safety regulatory agencies participated in
the stakeholder groups that helped develop the findings on which this
proposal is based and provided guidance through NARUC in the form of a
resolution. PHMSA action is consistent with this resolution.

G. Executive Order 13211

    This NPRM is not a ``significant energy action'' under Executive
Order 13211 (Actions Concerning Regulations That Significantly Affect
Energy Supply, Distribution, or Use). It is not likely to have a
significant adverse effect on supply, distribution, or energy use.
Further, the Office of Information and Regulatory Affairs has not
designated this NPRM as a significant energy action.

H. Unfunded Mandates

    PHMSA estimates that this NPRM does impose an unfunded mandate
under the 1995 Unfunded Mandates Reform Act (UMRA). PHMSA estimates the
rule to cost operators $155.1 million in the first year of the
regulations, which is higher than the $100 million threshold (adjusted
for inflation, currently estimated to be $132 million) in any one year.
The Regulatory Impact Analysis performed under EO 12866 requirements
also meets the analytical requirements under UMRA, and PHMSA has
concluded the approach taken in this regulation is the least burdensome
alternative for achieving the NPRM's objectives.

I. National Environmental Policy Act