Document ID: PHMSA-RSPA-2004-19854-0079
Agency: phmsa
Document Type: Rule
Title: Pipeline Safety: Integrity Management Program for Gas Distribution Pipelines
Posted Date: 2008-06-25T04:00Z

[Federal Register: June 25, 2008 (Volume 73, Number 123)]
[Proposed Rules]               
[Page 36015-36034]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[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.

[[Page 36016]]

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

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

Privacy Act Statement

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

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

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

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

I. Background

A. Integrity Management

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

B. Nature of U.S. Distribution Pipeline Systems

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

[[Page 36017]]

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

C. Safety of Distribution Pipeline Systems

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

D. Distribution Pipeline Safety Regulation

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

[[Page 36018]]

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

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

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

[[Page 36019]]

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

    The gas distribution industry recognized the need to consider its 
safety record and to determine if additional actions are needed. In 
late 2003, the American Gas Foundation (AGF) launched a study of the 
safety performance and integrity of gas distribution pipeline systems. 
Currently, operators must report an incident to PHMSA if it meets the 
reporting criteria in 49 CFR Part 191. The AGF study examined the 
record of incidents reported to PHMSA on gas distribution pipeline 
systems from 1990 through 2002 (the latest year for which data were 
complete at the time the study began) and compared that record to 
incidents reported for transmission pipelines over the same period.
    The AGF study analyzed trends in reported incidents and focused 
specifically on incidents involving deaths or injuries requiring 
hospitalization (called ``serious incidents'' in the study). A joint 
team, the Distribution Infrastructure Government-Industry Team (DIGIT), 
was established to oversee the AGF study. This team consisted of 
representatives of the AGF, the American Public Gas Association, and 
State pipeline safety regulators. PHMSA took part in DIGIT as an 
observer.
    The AGF published its findings in January 2005.\5\ The AGF study 
found a downward trend in serious incidents over the 13-year period 
analyzed at a 95 percent statistical confidence level. (No 
statistically significant trend was found when considering all reported 
incidents.) The number of serious incidents per 100,000 miles of 
distribution pipeline was essentially the same as that for gas 
transmission pipelines over the analyzed period. There are many more 
miles of distribution pipelines, however. Historically, distribution 
pipeline incidents result in more deaths and injuries than incidents on 
gas transmission or hazardous liquid pipelines, largely because 
distribution lines are located in populated areas and constitute a much 
larger share of the mileage of working pipelines.
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    \5\ American Gas Foundation, ``Safety Performance and Integrity 
of the Natural Gas Distribution Infrastructure,'' January 2005, 
available at 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

[[Page 36020]]

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

III Recommendations or Mandates of Oversight Bodies

A. DOT Inspector General

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

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

C. Congressional Mandate

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

IV. Stakeholder Groups

A. Stakeholder Groups' Involvement

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

[[Page 36021]]

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

B. Stakeholder Groups' Findings

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

C. Stakeholder Conclusions

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

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

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

[[Page 36022]]

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

D. Findings Relevant to Leak Management

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

E. Stakeholder Considerations Regarding Excess Flow Valves

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

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

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

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

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

[[Page 36023]]

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

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

V. Public Meetings

A. Public Meetings Concerning Distribution Integrity Management

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

B. EFV Public Meeting

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

[[Page 36024]]

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

[[Page 36025]]

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

[[Page 36026]]

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.

[[Page 36027]]

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

[[Page 36028]]

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

[[Page 36029]]

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

[[Page 36030]]

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).

[[Page 36031]]

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

[[Page 36032]]

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

E. Executive Order 13084

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

F. Executive Order 13132

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

G. Executive Order 13211

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

H. Unfunded Mandates

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

I. National Environmental Policy Act

    PHMSA analyzed this NPRM in accordance with section 102(2)(c) of 
the National Environmental Policy Act (42 U.S.C. 4332), the Council on 
Environmental Quality regulations (40 CFR 1500-1508), and DOT Order 
5610.1C, and has preliminarily determined this action will not 
significantly affect the quality of the human environment. The 
Environmental Assessment is in the Docket.

List of Subjects in 49 CFR Part 192

    Integrity management, Pipeline safety, Reporting and recordkeeping 
requirements.

    In consideration of the foregoing, PHMSA proposes to amend part 192 
of title 49 of the Code of Federal Regulations as follows:

PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: 
MINIMUM FEDERAL SAFETY STANDARDS

    1. The authority citation for part 192 continues to read as 
follows:

    Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 
60113, and 60118; and 49 CFR 1.53.

Sec.  192.383  [Removed]

    2. Section 192.383 is removed.
    3. In part 192, a new subpart P is added to read as follows:
Subpart P--Gas Distribution Pipeline Integrity Management (IM)
Sec.
192.1001 What do the regulations in this subpart cover?
192.1003 What definitions apply to this subpart?
192.1005 What must a gas distribution operator (other than a master 
meter or LPG operator) do to implement this subpart?
192.1007 What are the required integrity management (IM) program 
elements?
192.1009 What must an operator report when plastic pipe fails?
192.1011 When must an Excess Flow Valve (EFV) be installed?
192.1013 How does an operator file a report with PHMSA?
192.1015 What records must an operator keep?
192.1017 When may an operator deviate from required periodic 
inspections under this part?
192.1019 What must a master meter or liquefied petroleum gas (LPG) 
operator do to implement this subpart?

Subpart P--Gas Distribution Pipeline Integrity Management (IM)

Sec.  192.1001  What do the regulations in this subpart cover?

    General. This subpart prescribes minimum requirements for an IM 
program for any gas distribution pipeline covered under this part. A 
gas distribution operator, other than a master meter or liquefied 
petroleum (LPG) operator, must follow the requirements in Sec. Sec.  
192.1005 through 192.1017 of this subpart. A master meter operator or 
LPG operator of a gas distribution pipeline must follow the 
requirements in Sec.  192.1019 of this subpart.

Sec.  192.1003  What definitions apply to this subpart?

    The following definitions apply to this subpart:
    Damage means any impact or exposure resulting in the repair or 
replacement of an underground facility,

[[Page 36033]]

related appurtenance, or materials supporting the pipeline.

Sec.  192.1005  What must a gas distribution operator (other than a 
master meter or LPG operator) do to implement this subpart?

    (a) Dates. No later than [INSERT DATE 18 MONTHS AFTER PUBLICATION 
OF THE FINAL RULE IN THE Federal Register] an operator of a gas 
distribution pipeline must develop and fully implement a written IM 
program. The IM program must contain the elements described in Sec.  
192.1007.
    (b) Procedures. An operator's program must have written procedures 
describing the processes for developing, implementing and periodically 
improving each of the required elements.

Sec.  192.1007  What are the required integrity management (IM) program 
elements?

    (a) Knowledge. An operator must demonstrate an understanding of the 
gas distribution system.
    (1) Identify the characteristics of the system and the 
environmental factors that are necessary to assess the applicable 
threats and risks to the gas distribution system.
    (2) Understand the information gained from past design and 
operations.
    (3) Identify additional information needed and provide a plan for 
gaining that information over time through normal activities.
    (4) Develop a process by which the program will be continually 
refined and improved.
    (5) Provide for the capture and retention of data on any piping 
system installed after the operator's IM program becomes effective. The 
data must include, at a minimum, the location where the new piping and 
appurtenances are installed and the material of which they are 
constructed.
    (b) Identify threats. The operator must consider the following 
categories of threats to each gas distribution pipeline: corrosion, 
natural forces, excavation damage, other outside force damage, material 
or weld failure, equipment malfunction, inappropriate operation, and 
any other concerns that could threaten the integrity of the pipeline. 
An operator must gather data from the following sources to identify 
existing and potential threats: incident and leak history, corrosion 
control records, continuing surveillance records, patrolling records, 
maintenance history, and ``one call'' and excavation damage experience. 
In considering the threat of inappropriate operation, the operator must 
evaluate the contribution of human error to risk and the potential role 
of people in preventing and mitigating the impact of events 
contributing to risk. This evaluation must also consider the 
contribution of existing DOT requirements applicable to the operator's 
system (e.g., Operator Qualification, Drug and Alcohol Testing) in 
mitigating risk.
    (c) Evaluate and prioritize risk. An operator must evaluate the 
risks associated with its distribution pipeline system. In this 
evaluation, the operator must determine the relative probability of 
each threat and estimate and prioritize the risks posed to the pipeline 
system. This evaluation must consider each applicable current and 
potential threat, the likelihood of failure associated with each 
threat, and the potential consequences of such a failure. An operator 
may subdivide the system into regions (areas within a distribution 
system consisting of mains, services and other appurtenances) with 
similar characteristics and reasonably consistent risk, and for which 
similar actions would be effective in reducing risk.
    (d) Identify and implement measures to address risks. Determine and 
implement measures designed to reduce the risks from failure of its gas 
distribution pipeline system. These measures must include implementing 
an effective leak management program and enhancing the operator's 
damage prevention program required under Sec.  192.614 of this part. To 
address risks posed by inappropriate operation, an operator's written 
IM program must contain a separate section with a heading `Assuring 
Individual Performance'. In that section, an operator must list risk 
management measures to evaluate and manage the contribution of human 
error and intervention to risk (e.g., changes to the role or expertise 
of people), and implement measures appropriate to address the risk. In 
addition, this section of the written IM program must consider existing 
programs the operator has implemented to comply with Sec.  192.614 
(damage prevention programs); Sec.  192.616 (public awareness); Subpart 
N of this Part (qualification of pipeline personnel), and 49 CFR Part 
199 (drug and alcohol testing).
    (e) Measure performance, monitor results, and evaluate 
effectiveness.
    (1) Develop and monitor performance measures from an established 
baseline to evaluate the effectiveness of its IM program. An operator 
must consider the results of its performance monitoring in periodically 
re-evaluating the threats and risks. These performance measures must 
include the following:
    (i) Number of hazardous leaks either eliminated or repaired, per 
Sec.  192.703(c), categorized by cause;
    (ii) Number of excavation damages;
    (iii) Number of excavation tickets (receipt of information by the 
underground facility operator from the notification center);
    (iv) Number of EFVs installed;
    (v) Total number of leaks either eliminated or repaired, 
categorized by cause;
    (vi) Number of hazardous leaks either eliminated or repaired per 
Sec.  192.703(c), categorized by material; and
    (vii) Any additional measures to evaluate the effectiveness of the 
operator's program in controlling each identified threat.
    (f) Periodic Evaluation and Improvement. An operator must 
continually re-evaluate threats and risks on its entire system and 
consider the relevance of threats in one location to other areas. In 
addition, each operator must periodically evaluate the effectiveness of 
its program for assuring individual performance to reassess the 
contribution of human error to risk and to identify opportunities to 
intervene to reduce further the human contribution to risk (e.g., 
improve targeting of damage prevention efforts). Each operator must 
determine the appropriate period for conducting complete program 
evaluations based on the complexity of its system and changes in 
factors affecting the risk of failure. An operator must conduct a 
complete program re-evaluation at least every five years. The operator 
must consider the results of the performance monitoring in these 
evaluations.
    (g) Report results. Report the four measures listed in paragraphs 
(e)(1)(i) through (e)(1)(iv) of this section, annually by March 15, to 
PHMSA as part of the annual report required by Sec.  191.11 of this 
chapter. An operator also must report these four measures to the State 
pipeline safety authority in the State where the gas distribution 
pipeline is located.

Sec.  192.1009  What must an operator report when plastic pipe fails?

    Each operator must report information relating to each material 
failure of plastic pipe (including fittings, couplings, valves and 
joints) no later than 90 days after failure. This information must 
include, at a minimum, location of the failure in the system, nominal 
pipe size, material type, nature of failure including any contribution 
of local pipeline environment, pipe manufacturer, lot number and date 
of manufacture, and other information that can be found in

[[Page 36034]]

markings on the failed pipe. An operator must send the information 
report as indicated in Sec.  192.1013. An operator must also report 
this information to the State pipeline safety authority in the State 
where the gas distribution pipeline is located.

Sec.  192.1011  When must an Excess Flow Valve (EFV) be installed?

    (a) General requirements. This section only applies to new or 
replaced service lines serving single-family residences. An EFV 
installation must comply with the requirements in Sec.  192.381.
    (b) Installation required. The operator must install an EFV on the 
service line installed or entirely replaced after [INSERT DATE 90 DAYS 
AFTER PUBLICATION OF THE FINAL RULE IN THE Federal Register], unless 
one or more of the following conditions is present:
    (1) The service line does not operate at a pressure of 10 psig or 
greater throughout the year;
    (2) The operator has prior experience with contaminants in the gas 
stream that could interfere with the EFV's operation or cause loss of 
service to a residence;
    (3) An EFV could interfere with necessary operation or maintenance 
activities, such as blowing liquids from the line; or
    (4) An EFV meeting performance requirements in Sec.  192.381 is not 
commercially available to the operator.

Sec.  192.1013  How does an operator file a report with PHMSA?

    An operator must send any performance report required by this 
subpart to the Information Resource Manager as follows:
    (a) Through the online electronic reporting system available at 
PHMSA's home page at http://phmsa.dot.gov;
    (b) Via facsimile to (202) 493-2311; or
    (c) Mail: PHMSA--Information Resource Manager, U.S. Department of 
Transportation-East Building, 1200 New Jersey Avenue, SE., Washington, 
DC 20590.

Sec.  192.1015  What records must an operator keep?

    Except for the performance measures records required in Sec.  
192.1007, an operator must maintain, for the useful life of the 
pipeline, records demonstrating compliance with the requirements of 
this subpart. At a minimum, an operator must maintain the following 
records for review during an inspection:
    (a) A written IM program in accordance with Sec.  192.1005;
    (b) Documents supporting threat identification;
    (c) A written procedure for ranking the threats;
    (d) Documents to support any decision, analysis, or process 
developed and used to implement and evaluate each element of the IM 
program;
    (e) Records identifying changes made to the IM program, or its 
elements, including a description of the change and the reason it was 
made; and
    (f) Records on performance measures. However, an operator must only 
retain records of performance measures for ten years.

Sec.  192.1017  When may an operator deviate from required periodic 
inspections under this part?

    (a) An operator may propose to reduce the frequency of periodic 
inspections and tests required in this part on the basis of the 
engineering analysis and risk assessment required by this subpart. 
Operators may propose reductions only where they can demonstrate that 
the reduced frequency will not significantly increase risk.
    (b) An operator must submit its proposal to the PHMSA Associate 
Administrator for Pipeline Safety or the State agency responsible for 
oversight of the operator's system. PHMSA, or the applicable State 
oversight agency, may accept the proposal, with or without conditions 
and limitations, on a showing that the adjusted interval provides a 
satisfactory level of pipeline safety.

Sec.  192.1019  What must a master meter or liquefied petroleum gas 
(LPG) operator do to implement this subpart?

    (a) General. No later than [INSERT DATE 18 MONTHS AFTER PUBLICATION 
OF THE FINAL RULE IN THE Federal Register] the operator of a master 
meter or a liquefied petroleum gas (LPG) gas distribution pipeline must 
develop and fully implement a written IM program. The IM program must 
contain, at a minimum, elements in paragraphs (a)(1) through (a)(5) of 
this section. The IM program for these pipelines should reflect the 
relative simplicity of these types of systems.
    (1) Infrastructure knowledge. The operator must demonstrate 
knowledge of the system's infrastructure, which, to the extent known, 
should include the approximate location and material of its 
distribution system. The operator must identify additional information 
needed and provide a plan for gaining knowledge over time through 
normal activities.
    (2) Identify threats. The operator must consider, at minimum, the 
following categories of threats (existing and potential): corrosion, 
natural forces, excavation damage, other outside force damage, material 
or weld failure, equipment malfunction and inappropriate operation.
    (3) Identify and implement measures to mitigate risks. The operator 
must determine and implement measures designed to reduce the risks from 
failure of its pipeline system.
    (4) Measure performance, monitor results, and evaluate 
effectiveness. The operator must develop and monitor performance 
measures on the number of leaks eliminated or repaired on its pipeline 
system and their causes.
    (5) Periodic evaluation and improvement. The operator must 
determine the appropriate period for conducting IM program evaluations 
based on the complexity of its system and changes in factors affecting 
the risk of failure. An operator must re-evaluate its entire program at 
least every five years. The operator must consider the results of the 
performance monitoring in these evaluations.
    (b) Records. The operator must maintain, for the useful life of the 
pipeline, the following records:
    (1) A written IM program in accordance with this section;
    (2) Documents supporting threat identification; and
    (3) Documents showing the location and material of all piping and 
appurtenances that are installed after the effective date of the 
operator's IM program and, to the extent known, the location and 
material of all pipe and appurtenances that were existing on the 
effective date of the operator's program.

    Issued in Washington, DC on June 20, 2008.
William H. Gute,
Deputy Associate Administrator for Pipeline Safety.
[FR Doc. 08-1387 Filed 6-20-08; 3:31 pm]

BILLING CODE 4910-60-P