Integrity Management Program for Gas Distribution Pipelines

Friday,
December 4, 2009

Part III

Department of
Transportation
Pipeline and Hazardous Materials Safety
Administration

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49 CFR Part 192
Pipeline Safety: Integrity Management
Program for Gas Distribution Pipelines;
Final Rule

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Federal Register / Vol. 74, No. 232 / Friday, December 4, 2009 / Rules and Regulations

DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials
Safety Administration
49 CFR Part 192
[Docket No. PHMSA–RSPA–2004–19854;
Amdt. 192–113]
RIN 2137–AE15

Pipeline Safety: Integrity Management
Program for Gas Distribution Pipelines

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AGENCY: Pipeline and Hazardous
Materials Safety Administration
(PHMSA), DOT.
ACTION: Final rule.
SUMMARY: PHMSA is amending 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 this rule are
similar to those required for gas
transmission pipelines, but tailored to
reflect the differences in and among
distribution pipelines. Based on the
required risk assessments and enhanced
controls, the rule also allows for riskbased 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 rule
establishes simpler requirements for
master meter and small liquefied
petroleum gas (LPG) operators,
reflecting the relatively lower risk of
these small pipelines.
In accordance with Federal law, the
rule also requires operators to install
excess flow valves on new and replaced
residential service lines, subject to
feasibility criteria outlined in the rule.
This final rule addresses statutory
mandates and recommendations from
the DOT’s Office of the Inspector
General (OIG) and stakeholder groups.
DATES: Effective Date: This Final Rule
takes effect February 2, 2010.
Comment Date: Interested persons are
invited to submit comment on the
provisions for reporting failures of
compression couplings by January 4,
2010. At the end of the comment period,
we will publish a document modifying
these provisions or a document stating
that the provisions will remain
unchanged.

Comments limited to the
provisions on reporting failures of
mechanical couplings should reference
Docket No. PHMSA–RSPA–2004–19854
ADDRESSES:

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and may be submitted in the following
ways:
• E-Gov Web site: http://
www.regulations.gov. This site allows
the public to enter comments on any
Federal Register notice issued by any
agency.
• Fax: 1–202–493–2251.
• Mail: DOT Docket Operations
Facility (M–30), U.S. Department of
Transportation, West Building, 1200
New Jersey Avenue, SE., Washington,
DC 20590.
• Hand Delivery: DOT Docket
Operations Facility, U.S. Department of
Transportation, West Building, Room
W12–140, 1200 New Jersey Avenue, SE.,
Washington, DC 20590 between 9 a.m.
and 5 p.m., Monday through Friday,
except Federal holidays.
Instructions: In the E-Gov Web site:
http://www.regulations.gov, under
‘‘Search Documents’’ select ‘‘Pipeline
and Hazardous Materials Safety
Administration.’’ Next, select ‘‘Notices,’’
and then click ‘‘Submit.’’ Select this
rulemaking by clicking on the docket
number listed above. Submit your
comment by clicking the yellow bubble
in the right column then following the
instructions.
Identify docket number PHMSA–
RSPA–2004–19854 at the beginning of
your comments. For comments by mail,
please provide two copies. To receive
PHMSA’s confirmation receipt, include
a self-addressed stamped postcard.
Internet users may access all comments
at http://www.regulations.gov, by
following the steps above.
Note: PHMSA will post all comments
without changes or edits to http://
www.regulations.gov including any personal
information provided.
FOR FURTHER INFORMATION CONTACT:
Mike Israni by phone at (202) 366–4571
or by e-mail at [email protected].
SUPPLEMENTARY INFORMATION:

I. Background
Existing integrity management
regulations cover 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). These regulations require
that operators of these pipelines 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.

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PHMSA published a Notice of
Proposed Rulemaking (NPRM) on June
25, 2008, (73 FR 36015) to extend its
integrity management approach to the
largest segment of the Nation’s pipeline
network—the gas distribution pipelines
that directly serve homes, schools,
businesses, and other natural gas
consumers. Significant differences
between gas distribution pipelines and
gas transmission or hazardous liquid
pipelines made it impractical to apply
the existing regulations to distribution
pipelines. The proposed rule
incorporated the same basic principles
as current integrity management
regulations but with a slightly different
approach to accommodate those
differences. PHMSA worked with a
number of multi-stakeholder groups to
help determine the best way to apply
integrity management principles to
distribution pipelines before publishing
the NPRM. The work and conclusions of
the stakeholder groups are described in
the NPRM.
As described in the NPRM, the
proposal was responsive to
recommendations from DOT’s Inspector
General and the National Transportation
Safety Board. It also proposed to
implement a requirement in the
Pipeline Inspection, Protection,
Enforcement and Safety Act (PIPES Act)
of 2006 that integrity management
requirements be established for
distribution pipelines.
The proposed rule also included a
provision to allow distribution pipeline
operators to apply for approval from
their safety regulators to adjust the
intervals at which they perform specific
safety requirements that current
regulations require to be performed at
specified intervals. This provision
recognized the basic principle
underlying integrity management—that
operators should identify and
understand the threats to their pipelines
and apply their safety resources
commensurate with the importance of
each threat. Operators devote resources
to comply with the core pipeline safety
regulations. These safety resources can
be made available for other purposes
where a low level of risk makes a longer
interval acceptable. Applying those
resources to other safety tasks to address
higher risks can result in an overall
improvement in safety.
In addition, the proposed rule would
have required distribution pipeline
operators to install excess flow valves
(EFV) in certain new and replaced
residential service lines. This provision
also implemented a requirement in the
2006 PIPES Act.

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II. Comments on the NPRM
PHMSA received 143 letters
commenting on the proposed rule. Of
these:
• 12 were from associations. This
includes national and regional
associations of gas distribution pipeline
operators and the National Association
of Pipeline Safety Representatives
(NAPSR), the Association of State
Pipeline Safety Regulators.
• 62 were from municipal
distribution pipeline operators.
• 45 were from non-municipal local
distribution pipeline operators.
• 15 were from State pipeline safety
agencies.
• 5 were from companies supplying
products and services to the industry.
• 1 was from a citizens’ group.
• 1 was from the Plastic Pipe
Database Committee (PPDC).
• 1 was from the Gas Piping
Technology Committee (GPTC).
• 1 was from an anonymous
commenter.

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General Comments
Virtually all comment letters
supported the proposed rule, with
notable exceptions for some of its
provisions. The vast majority of
commenters commended PHMSA for
the inclusive way in which the
background for the proposed rule was
developed. Most commenters who took
exception to particular provisions in the
proposed rule objected to those
provisions as being beyond what
stakeholder groups had suggested.
The anonymous commenter suggested
that the proposed rule is not needed and
noted that accidents happen. One
operator suggested that this entire
proposal is unnecessary, since existing
rules are adequate to assure safety. One
operator also opposed the proposed
rule, noting that system differences
mean that the concepts used on
transmission lines do not apply to
distribution and suggesting that the
burden of implementing integrity
management for distribution pipelines
would cause more harm than good. One
state pipeline safety regulatory agency
also opposed the proposed rule, noting
that the existing body of regulations has
resulted in a very low number of deaths
annually from distribution pipeline
accidents and suggesting that the new
requirements would therefore not be
cost-beneficial. The State agency also
noted that the new rule will impose
additional work on already-burdened
State pipeline safety regulators.
PHMSA has considered these
comments but still considers it
necessary to issue a rule requiring

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integrity management for distribution
pipelines. While accidents may
continue to occur, that does not mean
that reasonable actions should not be
taken to avoid those accidents that
could be prevented. PHMSA concludes
that the flexibility inherent in the rule,
as modified in response to other
comments (described below),
adequately addresses concerns based on
differences among distribution
pipelines. PHMSA also concludes that
the changes made in response to other
comments will reduce implementation
costs and that the rule will be costbeneficial. PHMSA is working with
State pipeline safety agencies to
increase the level of Federal financial
support provided for State programs.
PHMSA notes that the vast majority of
distribution pipeline operators and State
regulators, and the associations that
represent them, supported the proposed
rule. The existing rules help assure an
admirable safety level. Still, significant
accidents continue to occur, if
infrequently. Experience has shown that
incidents are most often caused by a
combination of circumstances. These
circumstances represent risks for the
pipeline involved, but may not affect
other pipelines. It is thus not practical
to create additional prescriptive
requirements to address these pipelinespecific risks. This rule (as the integrity
management requirements for other
types of pipelines that preceded it)
requires that operators evaluate their
pipelines to identify the risks important
to their circumstances and take
appropriate actions to address those
risks.
This IM regulation for distribution
operators requires an operator to
conduct a comprehensive evaluation of
its system to better identify threats to
the system, to implement additional
measures to help prevent accidents from
occurring and to mitigate the
consequences if an accident does occur.
IM provides for a more systematic and
comprehensive approach to preventing
failures. Accordingly, PHMSA considers
this the most effective means to effect
further reductions in the number of
pipeline incidents. The regulatory
analysis supporting this rule considers
the improvement in safety that is
expected to result and explicitly
recognizes the current low frequency of
serious accidents.
Specific Comments
There was a broad consensus among
commenters that several provisions in
the proposed rule should be deleted or
significantly modified. In most cases,
the consensus included parties from
‘‘commercial’’ and municipal operators

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(and their associations) and State
regulators. Many additional comments
were made, often suggesting specific
changes needed to improve the
proposed rule or to make clear the
actions required to comply. These
comment topics are:
Comment Topic 1 Plastic Pipe Reporting.
Comment Topic 2 Performance Through
People.
Comment Topic 3 ‘‘Damage’’ Definition.
Comment Topic 4 Implementation Time.
Comment Topic 5 Rule Structure and
Implementation.
Comment Topic 6 Alternative Intervals.
Comment Topic 7 IM Requirements for
Master Meter and LPG Operators.
Comment Topic 8 Transmission Lines
Operated by Distribution Operators.
Comment Topic 9 Part 192—Requirement
References.
Comment Topic 10 Hazardous Leak
Definition.
Comment Topic 11 Required
Documentation.
Comment Topic 12 Excess flow valves.
Comment Topic 13 Guidance.
Comment Topic 14 Leak monitoring.
Comment Topic 15 State authority.
Comment Topic 16 IM program evaluation
and improvement.
Comment Topic 17 Permanent marking of
plastic pipe.
Comment Topic 18 Continuing
surveillance.
Comment Topic 19 Information gathering.
Comment Topic 20 Knowledge of pipeline.
Comment Topic 21 Threat identification.
Comment Topic 22 Risk assessments.
Comment Topic 23 Performance measures.
Comment Topic 24 Regulatory analysis.
Comment Topic 25 IM for new pipelines.
Comment Topic 26 Annual report form.

A discussion of each comment topic
and PHMSA’s response to each follows:
Comment Topic 1: Plastic pipe
reporting.
Commenters universally rejected the
proposal to require reporting of all
plastic pipe failures. Commenters noted
that the plastic pipe data committee
(PPDC) includes representatives of all
stakeholder groups and has several
years of data for identifying trends that
would be lost if PPDC were no longer
used. Commenters believe PPDC has
done an excellent job of collecting and
analyzing operating experience with
plastic pipe. According to commenters,
operators of approximately 75 percent of
installed plastic pipe mileage
voluntarily provide information to
PPDC. While this is less than the 100
percent participation that would result
from a mandatory reporting
requirement, commenters maintained
this is sufficient data to draw
statistically significant conclusions
about the performance of all plastic
pipe.
Many commenters thought PHMSA’s
concern that information from PPDC is

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not available to the entire industry is
unjustified. These commenters noted
that PPDC issues summary reports, that
trade associations (who participate in
PPDC) provide information to their
members, and that PHMSA has issued
advisory bulletins concerning
significant PPDC conclusions. Many
operators commented that they would
not have the time or resources to review
detailed failure information on their
own, and that the information currently
provided by the trade associations and
PHMSA advisories is useful to them.
Some commenters suggested that the
rule require operators to make use of
this information. AGA and one operator
suggested that the requirement to report
plastic pipe failures be replaced with a
requirement that operators consider
industry and government advisories in
evaluating plastic pipe performance as
part of their DIMP programs. They
believe this would be more effective in
addressing PHMSA’s underlying
concern of operators not considering
relevant information than would
mandatory reporting. All who addressed
this subject agreed that replacing the
current system with mandatory
reporting of all failures would be
unreasonably burdensome and would
not improve knowledge or safety. PPDC
commented that mandatory reporting is
not needed as they have the necessary
structure and participation. PPDC
suggested that it would take years to
collect enough data to duplicate the
information they already have on hand.
PHMSA response: PHMSA is
persuaded that the data collection
burden is not warranted at this time
given the current system of PPDC
analysis of plastic pipe failure trends
and dissemination of lessons learned
from this analysis via PPDC reports and
trade association communications and
through our advisories. The final rule
does not include the requirement to
report all plastic pipe failures.
The proposed requirement included
reporting failures of couplings used
with plastic pipe. PHMSA has retained
this requirement for compression
couplings. This final rule includes a
requirement that operators report
failures of compression coupling as part
of their annual reports. This provision
was an included part of proposed
§ 192.1009, which would have required
reporting of ‘‘each material failure of
plastic pipe (including fittings,
couplings, valves and joints)’’ (emphasis
added). As described above, PHMSA
has deleted from the final rule the
requirement to report plastic pipe
failures, since it was persuaded by the
public comments that PPDC is
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data and disseminating the results of its
analysis broadly. PPDC does not,
however, collect data on couplings used
to join plastic pipe, since the body of
most couplings is metal. Coupling
failure has been the cause of a number
of incidents on distribution pipelines in
recent years and the subject of several
PHMSA advisories. Additional data
concerning coupling failures is needed
to enable PHMSA to determine if
additional requirements are needed to
help prevent future incidents from
coupling failure. Accordingly, PHMSA
has retained the included element of
reporting of coupling failures in this
final rule.
The final rule provision is not limited
to couplings used on plastic pipe.
PHMSA understands that the principal
use for couplings in distribution
pipeline systems is to connect plastic
pipe or to connect plastic pipe to metal
pipe (including risers, etc.). PHMSA
recognizes that it is possible for
mechanical couplings to be used to
connect metal pipe to metal pipe, and
that reporting of failures involving such
connections would not have been
encompassed by the proposed
requirements related to plastic pipe in
the NPRM. PHMSA believes that use of
couplings in applications that do not
involve plastic pipe is rare.
Nevertheless, PHMSA invites public
comment on the extension of this
proposed requirement to include
reporting of failure of couplings used in
metal pipe. Comments should be
submitted by January 4, 2010. Based on
the comments we receive, we will
consider modifying the provision. At
the end of the comment period, we will
either issue a modification or a notice
stating that the section stands as
written.
An operator is not required to collect
coupling failure information until
January 1, 2010. We expect to issue any
modifications to this section prior to
that date. If we are delayed in issuing a
modification, we will then consider
further delaying the compliance date for
section 192.1009. PHMSA is issuing, in
conjunction with this final rule, a 60day notice regarding amendments to the
Annual Report form, which includes
changes related to this reporting
requirement. Until PHMSA announces a
modification, operators should plan to
report the information described in the
60-day notice.
Comment Topic 2: Performance
through people.
Commenters opposed the
performance through people (PTP)
element and the proposed requirement
that each IM plan include a section
entitled ‘‘Assuring Individual

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Performance.’’ Commenters maintained
that the proposed requirement is vague
and likely unenforceable and that it
creates confusion and diminishes the
focus on the core issues of importance
to IM. They pointed out, as did PHMSA
in the NPRM’s preamble, that other
regulations currently address the impact
of people on pipeline safety. These
regulations include Operator
Qualification, Drug and Alcohol
requirements, Damage Prevention, and
Public Awareness. Commenters noted
that the proposed PTP requirement is
unclear about what, if any, additional
actions are expected, and that having to
refer to actions taken under these other
requirements in an IM plan creates an
unnecessary additional paperwork
burden. NAPSR, American Public Gas
Association (APGA), GPTC, and
operators suggested that PHMSA should
not presume that action is required by
all operators to address the threat of
inappropriate operation. These
commenters noted that studies,
including those conducted by the
American Gas Foundation (AGF) and
Allegro and referred to in the preamble
of the NPRM, have shown that this
threat poses a very small risk; PHMSA
data shows it to be the cause of only 3%
of all leaks.
PHMSA response: PHMSA has not
included PTP requirements in the final
rule. PHMSA agrees the provision is
largely duplicative of other existing
regulations. Nevertheless, the final rule
still requires that operators evaluate all
threats applicable to their pipeline
systems. Thus, operators for which
inappropriate operation is a threat of
concern will be required to address that
threat.
Comment Topic 3: ‘‘Damage’’
definition.
In the NPRM, PHMSA proposed to
add a new definition for ‘‘damage’’
applicable to the IM subpart. The
proposed definition was ‘‘any impact or
exposure resulting in the repair or
replacement of an underground facility,
related appurtenance, or materials
supporting the pipeline.’’ This term is
being defined because of a provision in
the proposed rule that would require
reporting the number of excavation
‘‘damages’’ as a performance measure.
Industry stakeholders universally
commented that the definition of
‘‘damage’’ should be limited to
excavation damage and to damage that
causes loss of gas (immediate leaks).
GPTC would further limit the definition
to ‘‘known’’ excavation damage. States
and NAPSR suggested defining
excavation damage vs. damage, but did
not suggest limiting damage of interest
to damage causing leaks. One operator

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suggested that the definition should also
include instances in which damaged
pipe is retired in place because damaged
pipe and appurtenances are not always
repaired or removed; the operator
suggested that the definition should
focus on the unplanned nature of the
repair, removal or retirement.
The commenters pointed out that
operators report data regarding leaks in
their annual reports but not other
damage. Operators are not now required
to collect data on damages that do not
result in leaks. Commenters contended
that extending the definition of damage
to encompass situations that do not
cause leaks will cause loss of continuity
with previous data and may cause
confusion. Some noted that statistically
better conclusions can be drawn if such
continuity is maintained. Some
commenters asked whether coating
damage or damage to anodes/test wires
would be included. Others noted that
discovery of latent damage, that may
have occurred years earlier, is not a
measure of the current effectiveness of
a damage prevention or integrity
management program. Industry
expressed concern about the additional
recordkeeping burden associated with
capturing data on non-leak damages.
Two operators suggested that the term
‘‘exposure’’ be eliminated from the
proposed definition of damage (or
excavation damage) because it is unclear
what this term adds. They question, for
example, whether washouts would be
included.
PHMSA response: PHMSA agrees that
excavation damage is of principal
concern and is the term that should be
defined. PHMSA does not agree,
however, that only excavation damage
that results in a leak is of concern.
Mitigating the threat of excavation
damage means implementing or
continuing actions that will minimize
the likelihood that excavation near the
pipeline will cause damage. Operators
must seek to prevent excavation ‘‘hits’’
of the pipeline, whether a hit results in
leakage or not (e.g., a glancing blow or
insufficient force to cause a leak). That
a hit occurs, regardless of whether it
causes leakage, is an indication that the
actions intended to prevent such an
occurrence have failed. Operators
cannot adequately evaluate the
effectiveness of their mitigative actions
for this threat, and PHMSA cannot
evaluate the effectiveness of these
actions on a national level, if non-leak
events are excluded. Assuring
continuity with past data is less
important than assuring that the data
being collected appropriately addresses
the event of concern.

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At the same time, PHMSA is
sympathetic to the need to have welldefined criteria identifying what
damage is to be included in
performance monitoring and
understands that a definition based on
whether a leak occurred would provide
clarity; however, it would not allow
operators and PHMSA to monitor the
effectiveness of damage prevention
measures.
Pipeline operators, as well as
operators of all underground facilities,
need to evaluate the effectiveness of
damage prevention efforts. The
Common Ground Alliance (CGA) is a
national group involving operators of all
types of underground facilities, as well
as representatives of excavators and
others who play a part in preventing
damage to underground facilities. CGA
has established the Damage Information
Reporting Tool (DIRT) to collect
information submitted voluntarily
concerning damage to underground
facilities. Some pipeline operators
participate in DIRT. DIRT defines
damage based on whether repair or
replacement of an underground facility
is required. This is very similar to the
definition proposed in the NPRM,
which also relied on the need to repair
or replace as the defining criterion.
PHMSA has modified the definition in
the final rule to match more closely the
language used in the DIRT definition of
excavation damage. PHMSA has omitted
the phrase ‘‘of exposure’’ used in the
DIRT definition, since this refers to
damage from causes other than
excavation (e.g., washout). The changes
in the definition in the final rule will
provide the needed clarity and will also
facilitate potential comparison of
distribution pipeline damage prevention
performance to that of other
underground facilities for which CGA
collects data. This change also obviates
the need to include retirement in the
definition because retirement of an
active pipeline will usually involve
replacement or bypass. Damage to the
protective coating or to the cathodic
protection that requires repair/
replacement is damage of concern in
evaluating the effectiveness of damage
prevention measures; therefore, the
definition in the final rule clarifies that
damage necessitating repair to coating
or to cathodic protection constitutes
excavation damage.
Comment Topic 4: Implementation
time.
Many industry commenters objected
to the requirement that IM plans be
‘‘fully implemented’’ within 18 months.
They suggested that ‘‘fully’’ be deleted.
IM plans inherently involve learning
more about the pipeline systems and

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associated risks, and it is not clear when
they will be ‘‘fully’’ implemented.
A few operators suggested we clarify
what is meant by ‘‘implement.’’ They
noted that it was not clear if this meant
that all databases must be fully
populated and that, if so, it cannot be
accomplished in 18 months. Many
industry commenters also objected to
the proposed requirement that
implementation occur within 18
months. They argued that many
operators will need to make changes in
how they collect and manage data,
including the need to purchase new
computers and develop new databases
or make other IT changes, and that these
changes take time. Industry also
suggested that it is not practical to
expect that plans will be implemented,
databases will be fully populated, etc.,
for all portions of complex distribution
systems in a short period of time. AGA
noted that Congress allowed 10 years for
full implementation of gas transmission
IM. Commenters varied in their
suggestions for a different
implementation deadline. Many
suggested 24 months, with one operator
clarifying that after such a period
operators should be required to have
developed and implemented a
‘‘framework’’ that will further develop
over time. One operator suggested one
year to develop plans/programs and
another year to implement. Others
suggested variations on this approach,
with 11⁄2 years allowed either for
development or implementation.
One operator commented that the
proposed rule was too ambiguous as to
the actions required to implement its
provisions. It stated that the rule lacks
the clarity needed to know what must
be done.
PHMSA response: PHMSA has
deleted the term ‘‘fully’’ from the final
rule. PHMSA has retained the 18-month
requirement. PHMSA recognizes that
implementing IM plans involves
learning and revision but does not agree
that this means it is necessary to stretch
out the implementation deadline. It is
important to implement—to begin the
iterative learning process—as soon as
practical. With ‘‘fully’’ being deleted, as
noted above, it is clear that
implementation is not expected to mean
that all problems have been identified
and resolved. PHMSA notes that 18
months is consistent with the period
suggested by many commenters for
developing IM programs and, with
deletion of the concept of ‘‘fully
implement,’’ believes this period is still
appropriate.
AGA’s comment is incorrect. Congress
allowed 10 years for gas transmission
operators to complete baseline

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assessments (i.e., physical inspection) of
the portions of their pipelines in high
consequence areas.1 The proposed rule
did not include a provision for
distribution pipeline operators to
conduct such assessments.
Transmission pipeline operators were
required to develop and implement IM
plans in one year.2
PHMSA disagrees with the comment
that the rule is ambiguous. This
comment was not echoed by the many
other operators or the trade associations
that submitted comments. Some
commenters identified specific areas
where they believed further clarity was
needed and PHMSA has made changes
where appropriate, as described below.
As a result, PHMSA concludes that the
actions required to implement the final
rule are clear.
Comment Topic 5: Rule structure and
implementation.
Several commenters addressed
specific issues associated with the
structure of the rule and language in
proposed § 192.1005 addressing what
gas distribution operators must do to
implement this new subpart. A
consultant and GPTC both suggested
that section headers within the rule not
be written as questions because
questions are inherently longer than
classic titles, and make the rule harder
to use.
AGA and several distribution
operators objected to the proposed
requirement that procedures describe
the ‘‘processes’’ for developing,
implementing and periodically
improving IM elements. The Iowa
Utilities Board (Iowa) also suggested
that this provision be modified to
remove the reference to processes. The
commenters noted that the term is
unclear and could be interpreted to
require elaborate algorithms. They noted
that the stakeholders concluded that
major technical changes are not needed,
which they interpret to mean that major
‘‘processes’’ are not required to
implement distribution IM. They
believe that deleting the term does not
affect the meaning of the proposed
requirement.
PHMSA response: The structure of the
regulation as question and answer is
part of the long-standing Governmentwide requirement to write regulations in
‘‘plain English.’’ PHMSA has been
consistently using this format in its
pipeline rulemakings for some time.
PHMSA has revised § 192.1005(b) to
delete the reference to ‘‘processes.’’
1 Pipeline Safety Improvement Act of 2002,
Section 14.
2 49 Code of Federal Regulations, Section
192.907.

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Comment Topic 6: Alternative
intervals.
Commenters generally favored the
proposed requirement that would allow
operators to propose alternative
intervals for part 192 requirements.
There were a number of comments
related to this provision and its
implementation.
a. Concept.
AGA, GPTC, and many gas
distribution operators supported the
proposal. They noted that shifting of
resources often is necessary to assure
safety efficiently. They believe that the
proposed rule would not be costbeneficial unless it allowed for such
adjustments. They noted that risk-based
intervals are more effective and efficient
and can result in improved safety and
reduced costs. In response to a preamble
question concerning advantages and
disadvantages of allowing operators to
adjust required intervals, some
operators commented that the
engineering work needed to establish
new intervals and the need for State
review and understanding of the basis
were disadvantages of PHMSA’s
proposal.
PHMSA response: This provision is
intended to facilitate realignment of
safety resources, where appropriate, to
promote efficiency without
compromising safety. Because operators
are in the best position to understand
the risks on their system, and where
resources should be effectively applied,
this provision is designed to give
operators that latitude to effectively
manage their systems. Approval from
regulators is necessary to prevent the
abuse of this provision. Operators are
not required to apply for adjusted
intervals. If the burden of engineering
work and seeking State review are too
burdensome, the operator may continue
to use the intervals in the regulations.
b. Process.
AGA, GPTC, and several operators
suggested that it will be important for
PHMSA to provide guidance to the
States for implementing alternative
intervals. One operator suggested a
federal ‘‘template’’ to be used by the
States. Commenters suggested that
consistency would be particularly
important for large companies that
operate pipelines in multiple states. One
commenter stated the process should be
‘‘streamlined.’’ NAPSR, however,
asserted that approval should be per
State procedures, with flexibility
provided for each State to consider its
particular circumstances. Iowa also
noted that such guidance is not needed.
The Massachusetts Department of
Public Utilities suggested that a process
needs to be defined for appeal of

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decisions related to proposals for
alternative intervals. They believe that
such a process should be consistent
with that for waivers under 49 U.S.C.
60118.
PHMSA response: State authority and
regulatory structures differ, and some
state regulators may need to seek
additional authority (from their state
government) to implement this
provision. States will implement this
provision under individual state
statutory authority in accordance with
the applicable certification under 49
U.S.C. 60105 of this title or agreement
under section 60106. PHMSA believes
most states will be able to establish
procedures under existing authority and
may already have procedures that can
be used for this purpose.
PHMSA agrees with NAPSR that
states need flexibility in implementing
this provision. PHMSA will develop
criteria for evaluating operator’s
alternative interval proposal in the
states where PHMSA exercises
enforcement authority over distribution
pipelines. States may be able to use
those criteria where they exercise
enforcement authority. Factors
important to each regulatory authority’s
consideration of proposed changes to
intervals for safety actions are also
likely to differ. These differences make
it impractical to develop a common
‘‘template’’ process.
PHMSA agrees that the regulatory
authority responsible for reviewing the
request should institute appropriate
administrative procedures for
processing requests for alternative
intervals, to include a process for
appealing a decision. States will
establish their own procedures for
review, and it is not appropriate for
PHMSA to impose a ‘‘streamlined’’
process on state actions.
c. Approving agency.
NAPSR, States, and some industry
commenters suggested that the rule be
clarified that approval must be
requested from the regulatory authority
exercising jurisdiction. They considered
the language in the proposed rule vague
as to whether a state or PHMSA was the
approving agency, or whether an
operator could apply to either. One
operator suggested that approval should
be by States.
PHMSA response: PHMSA has always
intended that the alternative interval
provision in this rule would allow the
regulatory authority exercising
jurisdiction over the operator of the
distribution pipeline to act on a
proposal to use alternative intervals. We
have clarified the language in the final
rule to remove any implication that an
operator may seek approval from either

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PHMSA or a state. Most distribution
pipelines are regulated by state agencies
and approval of changes proposed by
those operators will be by the state.
d. Evaluation of proposals.
A number of commenters addressed
the proposed requirement that operators
proposing alternative intervals
demonstrate that a reduced frequency
will not significantly increase risk.
NAPSR proposed that operators should
be required to demonstrate enhanced
system safety or, at minimum, that
operation would be at least as safe
under the proposed alternative. Iowa
suggested a requirement for a
substantially equal or superior level of
safety. One operator requested that the
meaning of a significant increase in risk
be clarified by example, noting that the
proposed language is unclear. Another
suggested that the rule should not
require a proposal for an alternative
interval to include a no-significant-risk
demonstration; the commenter noted
that the core pipeline safety regulations
are not risk based and suggested that
risk must be considered on an overall
basis vs. change-by-change.
Although commenters generally
supported consistency between
regulatory authorities, commenters also
suggested that there is no single basis
for judging the adequacy of the
engineering basis for a proposed change,
and that it is not practical or necessary
to define requirements for performance/
data analysis. One operator suggested
that engineering analyses should be
judged on whether they are performed
by an engineer, are subject to internal
review, use good data, and include
logical analyses and conclusions. GPTC
and one operator suggested that no
additional analysis should be required if
performance measures show that risk
mitigation is effective.
AGA and several commenters noted
that there should be no arbitrary limit
on the change in interval that will be
allowed.
PHMSA response: The rule does not
require and PHMSA does not
contemplate that operators will produce
a precise quantitative estimate of risk.
Accordingly, PHMSA recognizes that it
is not easy to demonstrate that any
action produces no significant increase
in risk. However, regulating safety
requires judgments weighing risk versus
costs. Judgments of this type are what
operators will need to support their
proposals and regulators will need to
consider. PHMSA does not agree that
any reduction in safety intervals is
unacceptable because the change alone
would result in some increase in risk.
Instead, the regulatory authority needs

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to make an overall judgment on the
adequacy of proposed changes.
PHMSA has revised the final rule to
require that alternatives, as part of the
overall IM plan, provide an equal or
improved overall level of safety. This
change is intended to eliminate any
implication that a quantitative estimate
of risk is required. PHMSA expects that
operators will be conscientious in
demonstrating that proposals produce a
level of safety that is equal or improved,
on an overall basis, and that states will
be reasonable in judging the adequacy of
proposed changes.
PHMSA also agrees that it is
unnecessary and likely impractical to
establish specific criteria for approval of
proposals for alternative intervals. Each
proposal must be considered as a whole
and on its own merits. PHMSA has not
adopted any of the various alternatives
suggested by commenters because each
regulatory authority must exercise its
judgment based on the circumstances of
each request. However, PHMSA also
recognizes the industry’s need for some
degree of consistency in how proposals
are evaluated. PHMSA intends to work
with the states to help assure a degree
of consistency.
PHMSA is not specifying any limit on
the intervals that may be authorized by
the regulatory authority. The regulatory
authority will be responsible for
determining safe intervals based on the
information in each operator’s proposal.
e. Opposition.
The Florida Public Service
Commission opposed the proposal to
allow alternative intervals. The
Commission maintained that waivers
(their characterization) inherently
reduce the established minimum safety
level. They believe that processing these
proposals will be burdensome and that
proposed waivers would generally not
be approved. If the provision is retained,
they suggest that the risk analysis used
as a basis for changes must be
transparent to the regulator. They also
suggest that the code be revised to
require that operations and maintenance
(O&M) plans be required to contain a
summary of maintenance tasks and
approved periodicity, since it will no
longer be possible to use a common
inspection template if operators are not
required to conduct actions at the same
intervals.
PHMSA response: Waivers from
regulatory requirements (sometimes also
called special permits) are a common
regulatory tool. PHMSA permits
pipeline operators to seek a special
permit 3 and considers such requests on
their merits. Although required periodic
3 49

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63911

actions address threats of concern and a
reduction in the periodicity of those
actions inherently involves an increase
in risk, adjustments to the frequency
may be warranted when safety resources
are applied to other areas of greater
concern. Contrary to the assertion of the
commenter, the use of waivers can
result in a reduction in overall risk (i.e.,
improvement in safety), and regulators
must make judgments regarding the
overall effect of proposed changes.
The final rule requires that the
regulatory authority make the decision
to approve or disapprove any proposal
for alternative intervals. PHMSA sees no
need to add a requirement that risk
analyses used for this purpose be
‘‘transparent’’ to regulators because an
operator will have to work with the
regulatory authority to provide enough
information to evaluate the requested
change. PHMSA also does not agree that
a requirement that each O&M plan
contain a summary of maintenance tasks
and periodicity is needed. Florida, or
other states, may require such changes
or other information needed to facilitate
their inspections as part of their process
of reviewing an operator’s proposal.
f. Costs and benefits.
Commenters generally agreed that any
additional cost to states should be
minimal. (NAPSR concurred, provided
that States are allowed to follow their
current procedures.)
Some comments suggested that the
alternative interval provision will be of
limited benefit. One operator suggested
that the proposed requirement is too
burdensome, involving significant
administrative costs and burden
associated with the need to use risk
analyses to justify all changes. Another
noted that there are limitations on the
ability of operators to move resources
from low-risk areas, including potential
changes to labor agreements and
reassignment of personnel. They
requested that the rule recognize these
limitations.
Some operators are concerned that
failure of state regulators to approve
alternative intervals will result in
implementing additional actions to
control risks without offsetting
reductions where risk is low, thus
increasing total costs.
PHMSA response: Cost issues are
addressed in the Regulatory Impact
Analysis and the Regulatory Flexibility
Analysis located in the docket for this
rulemaking.
This provision imposes no burden on
operators. Use of alternative intervals is
voluntary. Operators who conclude that
obtaining approval would be too
burdensome or that it would be too
difficult to realign safety resources need

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not apply. PHMSA therefore sees no
need to revise the rule language to
recognize that such situations may exist.
Operators apply safety resources to
purposes other than inspections/actions
required periodically by regulation.
Operators will be able to realign those
resources without regulatory approval,
based on insights that their risk analyses
may supply, providing a means by
which they can make their safety
activities more efficient, thereby
permitting them to avoid increased
costs.
g. An industry consultant suggested
that the current requirement to inspect
inside meter sets for atmospheric
corrosion at 3-year intervals should be
changed. He noted that experience
shows these inspections are not needed
and it is more efficient to change the
requirement on a national basis.
PHMSA response: This is an example
of a required periodic inspection where
an operator could propose a
modification if its analysis showed
devoting resources in another area
would be more beneficial from a safety
standpoint. Changing this periodic
requirement on a national basis is
outside the scope of this rulemaking.
h. Some operators suggested that
implementation of alternative intervals
should be allowed, based on risk
analysis, without requiring regulatory
approval. They noted that reductions in
effort, where found appropriate, are an
integral part of implementing a riskbased approach. They expressed
concern that state regulators will be
unwilling to approve reductions from
established intervals which, although
not risk-based, are an accepted norm.
PHMSA response: PHMSA does not
think regulatory approval should be
eliminated. Regulatory oversight is
appropriate for changes that involve
reducing safety actions currently
required by regulation. PHMSA
recognizes that there may be some
reluctance to approve reductions from
an established norm; however, PHMSA
plans to assist states to determine
appropriate methods to evaluate
proposals. PHMSA believes that these
efforts will serve to address any
reluctance on the part of state regulators
to consider alternative intervals.
Comment Topic 7: IM requirements
for master meter and LPG operators.
Many comments addressed the
proposed limitation of requirements for
master meter and LPG operators (MM/
LPG) and PHMSA’s request for
comment on these limitations. PHMSA
asked whether the proposed limitations
were appropriate, whether further
limitations were needed or if these
operators should be exempt from IM

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requirements. PHMSA also asked
whether similar limitations should be
afforded to other types of operators.
a. Proposed limitations are
inappropriate.
Two major trade associations
addressed the proposed limitations for
master meter and LPG operators.
(Neither group’s members include
operators of this size.) AGA suggested
that these smaller operators should be
required to implement distribution IM,
but that the requirements should be
scalable, recognizing the uncomplicated
nature of their facilities.
APGA agreed that MM/LPG should
not be excluded from IM requirements.
They noted that if mandatory reporting
of plastic pipe damages is eliminated (as
they suggested) the limitation
essentially becomes an exclusion from
filing annual reports. Master meter
operators are currently excluded from
annual report requirements. APGA
‘‘would not object’’ to adding a
requirement that master meter and LPG
operators evaluate and prioritize risk.
APGA sees risk ranking as an integral
part of assessing risks, and believes it
will occur whether or not it is required
explicitly in the rule.
NAPSR, Connecticut Department of
Public Utility Control, Pennsylvania
Public Utility Commission (PPUC), and
several operators also commented that
MM/LPG should be subject to IM
requirements. They referenced the
conclusion of the stakeholder groups
that distribution IM should apply to all
distribution operators. These
commenters did not agree that these
operators pose less risk, and maintained
that simpler systems will inherently
have simpler programs. They also noted
that some master meter operators are
much larger than the NPRM stated.
PPUC explained that there are two
master meter operators in its state with
more than 6,000 customers. Other
commenters noted that there is limited
data on these systems, since they do not
report incidents, and thus the risk may
not be small.
The Arizona Corporation Commission
(AZCC) commented that all LPG
operators should not be treated like
master meters, since some serve small
towns, like local distribution companies
and have the same limited control over
the principal threat of excavation. AZCC
suggested that LPG operators who serve
a city, town, or other municipality
within a specified service area as
defined by the state agency with
authority should meet the same
requirements as other distribution
system operators. AGA and NAPSR
noted that LPG poses unique risks
because the product is heavier than air,

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unlike natural gas. Leaks from these
systems will not safely disperse, as will
leaks from natural gas distribution
systems.
PHMSA response: PHMSA is
persuaded that there is a reasonable
criterion to distinguish between LPG
operators. PHMSA’s concern with
overwhelming small operators with
limited resources and technical
expertise is not applicable to LPG
systems serving hundreds or thousands
of customers because those operations
are more like small natural gas
distribution system operators. PHMSA
notes that existing regulations include a
criterion to differentiate between large
and small LPG operators. Section 191.11
excludes LPG operators serving fewer
than 100 customers from a single source
from filing annual reports. Other LPG
operators are required to file such
reports. PHMSA has revised the final
rule to embrace this same criterion. LPG
operators serving fewer than 100
customers from a single source are
treated like master meter operators.
Other LPG operators must meet the
same requirements as natural gas
distribution pipeline operators.
We are also persuaded that MM/small
LPG operators should not be exempt
from ranking risks—a requirement we
had applied to all other distribution
operators in the proposed rule. We
believe that these operators will gain a
better understanding of their systems by
going through the ranking process.
Ranking the risks is almost inherent in
the other requirements and should not
impose an additional burden on these
operators. PHMSA has added an
element to rank risks to the
requirements applicable to MM/LPG
systems.
b. MM/LPG should be subject to
limited IM requirements.
The Indiana Utility Regulatory
Commission does not agree that MM/
LPG should be subject to the same
requirements as other operators. Indiana
commented that although there are
reasons that master meter operators
could be perceived as posing higher risk
(e.g., lack of expertise/resources,
distributing gas is not primary business,
high population density), there has been
no record of serious incidents at master
meters in Indiana. They stated that these
operators struggle to comply with
existing rules and will have limited
ability to analyze risks, even if the
computer program APGA is developing
(Simple, Handy, Risk-based, Integrity
Management Program—SHRIMP) is
available. Indiana suggested we should
either exclude master meter operators
from this rule or subject them to more
limited requirements and allow them to

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spend their limited resources achieving
compliance with existing regulations.
While not supporting total exclusion,
Missouri and New Hampshire state
regulators supported limited
requirements for MM/LPG. AZCC
commented that the rule should be
prescriptive and simple for master meter
and small LPG operators, since these
operators have limited capability, can be
easily overwhelmed and may, if that
happens, do nothing. The New Mexico
Public Regulation Commission
(NMPRC) supported excluding MM/LPG
from administrative requirements of the
proposed rule.
Iowa did not take a position on
limiting requirements; however, Iowa
and a large operator suggested that
evaluation and prioritization of risks
should not be excluded for MM/LPG.
They see this as a critical step, and not
particularly burdensome.
PHMSA response: While PHMSA
agrees that there are some ‘‘large’’ MM
operators, most of them are very small.
Unlike the large/small LPG operator
distinction, which exists in current
regulations, all MM operators are treated
the same, irrespective of size. Therefore,
in this final rule, all MM are subject to
the limited IM requirements.
The final rule imposes requirements
similar to those for other operators but
with more limited requirements for
documentation, consistent with how
these operators are treated in other
regulations. They will not be required to
report performance measures as they do
not file annual reports.4 Although these
requirements are similar to those
applicable to other operators, we have
presented them separately, emphasizing
that these programs should reflect the
simplicity of the pipelines.
Some comments in response to the
NPRM and comments made during
earlier stakeholder discussions have
disagreed with PHMSA’s contention
that MM/LPG operators pose less risk.
Risk is generally considered to be the
product of the likelihood of adverse
events and their consequences.
Determining risk thus requires
knowledge of how often events occur
and the consequences they produce.
MM/LPG operators are not required to
submit written incident reports. They
are, however, required to make
telephonic reports.5 Events with serious
consequences (e.g., death or serious
injury) are also likely to be reported in
local news and thus to come to the
attention of regulatory authorities.
PHMSA therefore believes it is unlikely
4 Operators of LPG systems serving more than 100
customers are required to file annual reports.
5 49 Code of Federal Regulations, section 191.5.

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a large number of significant events
have occurred on MM/LPG systems that
are not reflected in incident data. That
data includes few serious incidents on
MM/LPG systems, supporting PHMSA’s
contention that the risk from these
systems, while not zero, is relatively
low. Indiana’s comments about the
dearth of serious accidents in the
incident record are consistent with
PHMSA’s understanding of the risk of
these systems.
c. MM/LPG should not be subject to
IM requirements.
The National Propane Gas Association
(NPGA) suggested that LPG operators
should be exempt entirely. NPGA sees
no perceived benefit from compliance
with the proposed requirements. They
noted that LPG systems are very small,
that they generally include pipe runs
measured in feet vs. miles, and that the
total quantity of gas that could be
released in an accident is limited by the
capacity of the supply tanks, a
limitation not shared with natural gas
systems. NPGA maintained that their
members are already sufficiently
regulated, mostly by states and through
the incorporation of NFPA Standard 58
(NFPA–58) into Part 192 by reference.
They believe that NFPA–58 mirrors the
requirements of Part 192 and the
proposed rule and noted that the
standard is already recognized as the
primary governing standard in
§ 192.11(c) which states that the
standard prevails in the event of a
conflict between its provisions and Part
192. NPGA also suggested that applying
this rule to LPG operators could have
unintended consequences. In a
competitive environment to reduce
costs, operators could break up their
systems to fall outside of regulation,
thus removing safety oversight
completely.
PHMSA response: In the NPRM we
proposed a simpler set of IM
requirements for MM/LPG operators,
but we asked if these operators should
be completely excluded from IM
requirements. The bulk of comments
supported limited requirements but
opposed excluding these operators,
arguing that simple pipelines would
need only simple IM plans. In the final
rule, PHMSA has not excluded these
operators.
LPG presents unique hazards;
accordingly, PHMSA believes pipeline
safety will be enhanced by larger LPG
operators engaging in more robust
integrity management activities. As
discussed above, large LPG operators are
subject to the full IM requirements in
the final rule, including the
administrative requirements. Because of
the physical nature of LPG and the

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63913

safety risks it presents, PHMSA is not
persuaded that small LPG operators
should be exempted. Furthermore,
NFPA Standard 58 does not ‘‘mirror’’
the integrity management requirements
in this rule and does not adequately
address the safety measures provided by
this final rule. IM requirements will
complement NFPA–58.
d. Limitations for small gas
distribution operators (other than MM/
LPG).
A consultant suggested that
distribution IM should be limited to
large operators at this time. He noted
that the PIPES Act does not mandate
such requirements for small operators
and suggested that a phased approach
would be prudent. He believes that
small operators do not have the
personnel or background to implement
these requirements and that the
associated costs will likely exceed the
benefits. He noted that the risk from
third-party damage on such systems is
small, as operators’ personnel see most
of the system daily. He supported
exclusion for small operators similar to
that proposed for MM/LPG and
suggested that PHMSA collect
additional data to see if additional
requirements are needed for these
operators. A large operator also
supported limited requirements for
small operators, and would include the
number of customers or mileage as a
threshold criterion.
The Washington Citizens Committee
on Pipeline Safety commented that the
number of services should not be used
alone to delineate small systems. They
suggested that the type and uniformity
of material, system complexity,
geographic spread, and other risk factors
be considered as well.
APGA suggested that criteria defining
a small system should not include
limitation to one pressure district and
should not limit the type of
appurtenances or equipment. APGA
commented that these differences do not
affect risk. Small distribution operators
already file annual reports, so APGA
believes that extending the proposed
limitations for MM/LPG would have no
value for other small operators.
NMPRC would exclude small
operators from the administrative
requirements of the proposed rule based
on the number of customers or staff.
NMPRC concluded that DIMP principles
would be beneficial for these operators
but that the associated administrative
burden is too great.
Missouri would extend all of the MM/
LPG limited requirements to small
operators.
PHMSA response: PHMSA has not
limited this rule to large operators. As

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noted in the NPRM, there is no
established threshold to distinguish
between large and small operators. In
addition, the PIPES Act did not
differentiate between large and small
distribution operators. The PIPES Act
requires, ‘‘the Secretary shall prescribe
minimum standards for integrity
management programs for distribution
pipelines.’’ 6 We received few comments
regarding how such a threshold might
be established.
Rather than delineating explicit
thresholds based on operator size,
PHMSA expects that operators with
small systems will need only simplified
plans. Operators will be able to scale
their programs according to the
complexity of their distribution systems.
For example, APGA’s SHRIMP program
will be available to assist small
operators in developing their IM plans.
e. Limitations for other operators.
One operator suggested that limited
requirements should also be established
for ‘‘circumstantial’’ or ‘‘incidental’’
operators. This operator is a large
company operating hazardous liquid
pipelines, but operates a single gas
service line from a local distribution
company main to a flare at a petroleum
barge dock. The operator believes it
would be burdensome to have a
distribution IM plan for this single
service line. A consultant and GPTC
also suggested that landfill gas operators
should be treated like MM/LPG, since
their systems are also small and pose
limited risk.
New Hampshire recommended that
operators of conventional distribution
systems that also operate LPG should be
allowed to use a single plan for both.
One operator suggested that LDC
operators that also operate MM/LPG
should be allowed to use a single DIMP
plan for both.
PHMSA response: As MM/LPG
operators have not been excluded from
IM requirements, we see no compelling
reason to exclude these other ‘‘small’’
operators. PHMSA considers that the
analysis of a small, simple system
should be relatively straightforward and
should result in a basic IM plan.
PHMSA notes the commenter operating
a single service line to a flare stack may
be considered a large volume customer
as long as the service line is not on
public property. This final rule does not
apply to in-plant piping to a large
volume customer. Companies that
conclude that compliance with a rule
would be overly burdensome due to
unique circumstances may have the
option to apply for a waiver (or special

permit), as permitted by the applicable
regulatory oversight authority.
The rule does not require that
operators of conventional distribution
systems that also operate LPG have
separate IM plans or that operators of
both MM and LPG systems have
separate plans for each. We expect that
plans developed for their conventional
pipelines in response to the other
requirements of subpart P should also
satisfy § 192.1015. PHMSA agrees that
operators with multiple ‘‘systems’’ may
benefit from having a single IM plan.
However, it is also possible that
operators who own multiple systems
may operate them separately and may
desire separate IM plans. Under the
final rule, operators will have the
flexibility to treat multiple systems
under a common plan, or to address
them separately.
Comment Topic 8: Transmission lines
operated by distribution operators.
Many industry commenters suggested
that piping operated by distribution
operators but which is classified as
transmission (mostly because it operates
at greater than 20% SMYS) should be
included in a distribution IM plan
rather than in a separate transmission
IM plan. These commenters suggested
that this could be done in this rule or
by changing the definition of a
transmission line. Commenters
explained that this ‘‘transmission’’
piping is usually operated as an integral
part of the distribution system, and that
it would be more efficient to treat it
under distribution IM than under a
separate transmission IM plan. Several
commenters recognized that additional
rulemaking may be needed to
accomplish this change.
PHMSA response: PHMSA has made
no change in response to these
comments. The NPRM did not address
changing the definition of transmission
pipeline; therefore, such an action is
outside the scope of this rulemaking.
The transmission IM regulations
already provide for alternative treatment
of low-stress transmission pipeline
(<30% SMYS) 7 in recognition that this
low-stress pipe is more likely to fail by
leakage rather than by rupture. PHMSA
also notes that stakeholder groups
studied the appropriateness of treating
low-stress transmission pipeline under
distribution IM programs. The groups
reviewed the existing research
concerning the likely failure mode of
low-stress transmission pipelines. The
record indicated that failure is expected
to be by leakage when the failure results
from corrosion. It is less clear that the
7 See

6 49

United States Code, section 60109(e)(1).

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§ 192.941, What is a low stress
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likely failure mode would be leakage
when the failure results from prior
mechanical damage (e.g., from outside
force). The stakeholder groups
concluded that additional technical
work is needed to better define the
threshold stress level at which the likely
failure mode transitions from leakage to
rupture to determine if low-stress
transmission pipeline should be
addressed under a distribution IM
program.8 PHMSA may consider this
change later but agrees with the
stakeholder conclusion that additional
research is required to support such a
change.
Comment Topic 9: Part 192
requirement references.
NAPSR, APGA, and a number of
operators objected to the proposed
requirement that all operators must
enhance their damage prevention
programs (proposed § 192.1007(d))
because the requirement is open-ended.
They suggested that § 192.614, which
requires such programs, should be
revised if current programs are deemed
inadequate.
A consultant suggested that leak
management requirements should be
included in § 192.723 and damage
prevention requirements in § 192.614.
He generalized this comment by noting
that PHMSA should avoid having two
regulations that address the same thing.
He considers IM as an extension of all
of Part 192, and believes that proposed
Subpart P should be limited to the highlevel approach to IM and related
documentation.
PHMSA response: The final rule
requires that operators have and
implement leak management programs.
Programs to manage known leaks are
different from periodic leak surveys
required by § 192.723.
Operators are required to implement a
damage prevention program under
§ 192.614. After further consideration,
PHMSA determined a requirement to
enhance damage prevention programs
on gas distribution systems through
integrity management was impracticable
because these programs are largely staterun. PHMSA is persuaded that
modifications to damage prevention
requirements for distribution systems
should be made through amendments to
§ 192.614 rather than through this
rulemaking. PHMSA has eliminated the
proposed requirement to enhance
damage prevention programs as part of
an integrity management effort.
Although all references to the damage
prevention requirements in § 192.614
8 PHMSA, ‘‘Integrity Management for Gas
Distribution: Report of Phase 1 Investigations,’’
December 2005, page 23.

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have been removed, operators may find
through the implementation of their IM
programs that improvements to their
damage prevention programs are
needed.
Comment Topic 10: Hazardous leak
definition.
Several commenters suggested we
define hazardous leaks. The proposed
rule would require reporting of the
number of hazardous leaks repaired or
eliminated as a performance measure.
APGA, GPTC, NAPSR, Washington
Citizens Committee on Pipeline Safety,
and several pipeline operators suggested
that a common definition is needed to
assure consistent reporting and the
ability to conduct meaningful analysis
of this performance measure. Most
suggested that the definition of a grade
1 leak in the current GPTC guidelines be
adopted. One operator suggested a need
to define the term ‘‘leak,’’ suggesting
that usage is not consistent across the
industry. AGA and a number of
operators suggested that any needed
definitions, other than excavation
damage, should be included on
reporting forms and their instructions
rather than in the code and that this
makes subsequent changes, if needed,
easier.
PHMSA response: Although a
‘‘hazardous leak’’ definition was not
explicitly part of our proposal, we did
propose regulatory text including that
term; accordingly, PHMSA has included
a definition for ‘‘hazardous leak’’ in the
final rule. This definition is drawn from
GPTC guidelines already used by many
operators to classify leaks. PHMSA does
not see a need to define other terms
suggested in comments for purposes of
this rule. PHMSA is also adding a
definition for small LPG operators to
improve readability of the Subpart P
regulations.
Comment Topic 11: Required
documentation.
Proposed documentation
requirements were seen as unreasonably
burdensome. In particular, the proposed
requirements to document ‘‘all’’
decisions and changes related to a
distribution integrity management (IM)
program and to keep all related records
for the life of the pipeline were seen as
unreasonable.
a. Scope of documentation.
Many commenters suggested deleting
all documentation requirements other
than the requirement to maintain an IM
plan. Others suggested limiting
documentation to significant changes, to
be defined at the operator’s discretion.
NAPSR suggested that written
procedures and documents supporting
threat identification should be limited,
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does not support safety. NAPSR would
limit the requirement for procedures in
proposed § 192.1005(b) to those that
‘‘reasonably describe’’ processes for
developing and implementing IM
elements. NAPSR further suggested
requiring that procedures ‘‘should
provide adequate direction so that a
person with reasonable knowledge of
gas distribution facilities can follow
them and produce a satisfactory result.’’
One operator suggested that all the
records that are needed are contained in
their damage prevention plan and
annual reports to PHMSA. Another
operator requested clarification
concerning the data to be captured to
represent the ‘‘material of which [newly
installed piping systems] are
constructed.’’ One operator commented
that the term ‘‘documents to support’’
decisions, analyses, or processes is
vague.
AGA and several operators suggested
changing proposed § 192.1015(c) from a
written procedure for ranking threats to
a description of how threats are ranked.
They maintained that detailed
procedures are not needed, but
acknowledged that master meter and
small LPG operators must be able to
explain what was done to rank threats.
Florida Public Service Commission
requested that operators be required to
include in their IM plans a summary
containing the risk analysis findings, the
effect on safety, and a schedule for
actions resulting from the distribution
IM program.
PHMSA response: In the NPRM, the
section regarding record retention
(NPRM § 192.1015; Final Rule
§ 192.1011) required the following
records: A written IM program;
documents supporting threat
identification; a written procedure for
ranking the threats; documents to
support any decision, analysis, or
process developed and used to
implement and evaluate each element of
the IM program; records identifying
changes made to the IM program, or its
elements, including a description of the
change and the reason it was made; and
records on performance measures.
PHMSA has removed this list of
documents and simplified the language
of the regulation to require operators to
maintain documentation demonstrating
compliance. Because of the simplified
language, AGA’s comment regarding
ranking threats is moot. Generally,
documentation demonstrating
compliance will include documentation
to show how the operator has fulfilled
the requirements of each element of
§ 192.1007. PHMSA believes this is the
type of information to which Florida
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PHMSA has revised § 192.1005 to
eliminate the proposed requirement that
operator procedures describe ‘‘the
processes’’ for developing and
implementing its IM program. Although
we did not include all of NAPSR’s
suggestions in the final rule language,
we have modified the language so that
the section now requires that operators
have procedures ‘‘for developing and
implementing the required elements.’’
Although PHMSA agrees that all
procedures should be clearly written so
that anyone who has to use them can
understand and follow them, we did not
include this language in the regulation
text.
b. Documentation retention.
Commenters proposed limiting
document retention to 10 years or, in a
few cases, through the next regulatory
audit cycle. Commenters universally
considered that these documents would
not be of value beyond these near-term
periods and noted that resources to
maintain such records would take away
from those available to operate and
maintain the pipelines.
GPTC and one operator suggested that
required retention of performance
measures be limited to 2 times the
program re-evaluation period. They
based this on the proposed 10-year
retention, which would be twice the
mandatory 5-year re-evaluation period.
They noted that operators who evaluate
their performance measures more
frequently would be overly burdened by
requirements to keep records beyond
their potential useful life.
Iowa suggested deleting the
requirements to retain, as records, a
written IM plan and a procedure for
ranking threats. They maintained that
these are not records, per se, but rather
are part of plans that are required to be
retained by other regulations.
One consultant suggested revising or
deleting the term ‘‘must’’ from the
requirement that an operator must retain
records for a specified period. He noted
that an operator who retained records
for a longer period would be in
technical violation of such a
requirement.
PHMSA response: PHMSA agrees that
the proposed requirements for
documentation retention were overly
broad. PHMSA concludes that retaining
documentation describing changes to an
IM plan will be useful for some period,
but agrees that these records would be
of limited or no use many years after the
changes are implemented. PHMSA has
revised the final rule to require that
operators maintain records
demonstrating compliance for 10 years,
and that these records must include
superseded IM plans.

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PHMSA disagrees that the IM plan is
not a record. PHMSA considers that
superseded IM plans are records—a
record of what the IM program consisted
of at a particular time. PHMSA does not
consider it necessary or appropriate to
delete the term ‘‘must’’ as recordkeeping
is not voluntary. The 10-year retention
requirement is a minimum requirement;
operators may maintain records for a
longer period.
Comment Topic 12: Excess flow
valves (EFVs).
A number of comments were made
concerning the proposed requirements
related to EFVs.
a. EFV in Subpart H.
AGA, APGA, NAPSR, a number of
operators and an industry consultant
suggested that the requirement to install
EFVs be moved to Subpart H rather than
remaining a part of IM requirements.
Although EFV installation is a PIPES
Act requirement, they noted that this is
not inherently an IM requirement. In the
NPRM, PHMSA proposed to delete from
Subpart H the requirement that
operators notify customers of the
availability of EFVs but to keep the
performance standards for EFVs in
Subpart H. The commenters consider
this separation unnecessary.
AGA, NAPSR and several operators
also requested that we clarify that EFVs
are not required to be installed on
branch service lines. They noted that
the PIPES Act mandate addressed
service lines to single family residences
and that it is impractical to install EFVs
on branch service lines.
PHMSA response: PHMSA has
relocated the requirement to install
EFVs to subpart H. It will now replace
§ 192.383. PHMSA has included in
revised § 192.383 a definition of service
line serving a single-family residence.
This definition excludes branch service
lines, consistent with the intent of our
proposal in the NPRM.
b. Installed EFVs as performance
measure.
APGA, GPTC, and several operators
suggested that the number of EFVs
installed should not be treated as a
measure of IM effectiveness. This
measure relates to the number of new or
replaced services and is unrelated to
whether IM is effective or not. These
commenters generally did not object to
collecting the data, only to its apparent
treatment as an IM performance
measure. One operator suggested that
this item simply be added to the annual
report. Another suggested not requiring
it to be reported at all. A third requested
clarification that the number to be
reported is the total number of EFVs
installed, which they believe to be
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PHMSA response: PHMSA agrees that
the number of EFVs installed is not a
measure of the effectiveness of a
distribution IM program. PHMSA
expects to need this information to
respond to questions from NTSB and
Congress (and perhaps other
organizations) concerning the
implementation of the PIPES Act
provision requiring that EFVs be
installed. The requirement to include
this information in the annual report
has been moved to § 192.383. See the
comment topic discussing the annual
report for more information.
c. Installation criteria.
Connecticut Department of Public
Utility Control recommended that the
EFV requirement be expanded beyond
the PIPES mandate to all situations in
which installation of an EFV is
technically feasible. One operator
suggested that the pressure criterion be
revised to specify that the distribution
system, rather than the service line,
must operate at a minimum of 10 psig
throughout the year.
PHMSA response: PHMSA has not
made either change. The installation
criteria included in the PIPES Act
reflect the performance standards that
have long been in 49 CFR § 192.381.
Most EFVs manufactured in the U.S.
comply with these criteria and PHMSA
considers them to define, for practical
purposes, where installation is feasible.
States have the ability to impose
additional requirements affecting
circumstances not enveloped within the
criteria in this rule if they can justify
such requirements under state
procedures. With respect to the
operator’s comment, the pressure at the
valve location, i.e., in the service line,
is the relevant criterion. It does not
matter if pressure at some other location
in the distribution system is lower than
required.
d. Replaced service line definition.
One operator requested that the rule
define a replaced service line as a
natural gas service line that is entirely
replaced, noting that this is consistent
with the PIPES Act. GPTC and Iowa
suggested that the definition of a
replaced line now in § 192.383(a) be
moved to § 192.381, since it would be
lost with repeal of § 192.383.
Missouri Public Service Commission
commented that installation should be
required for circumstances other than
entire replacement of an existing service
line. They contend that the current
practice, pursuant to § 192.383, is to
require an operator to notify a customer
of the availability of an EFV if
replacement work provides an
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the entire service line. The Commission
believes that PHMSA’s intent was to
require installation in the same
circumstances and believes that the
language in the proposed rule does not
implement that intent.
PHMSA response: We have revised
the reference to ‘‘installed or entirely
replaced’’ to use the defined term
‘‘replaced service line’’ to eliminate
confusion. PHMSA has retained the
definition of replaced service line in the
revised § 192.383(a) and requires
installation for situations meeting this
definition. EFVs, to be effective, are
installed at or near the connection to the
main. Using the defined term ‘‘replaced
service line’’ avoids the
misunderstanding expressed by the
commenter; PHMSA does not intend to
mandate additional excavation to install
an EFV when another portion of the
service line is excavated. The cost of
excavation is the significant factor in
installing an EFV, and PHMSA
considers it appropriate to require
installation when the area near the
connection to the main has been
exposed and an opportunity to install
exists. It would not be prudent to forego
this opportunity for installation simply
because some downstream portion of
the service line is not replaced.
e. Master meter/LPG exclusion.
NAPSR and Southwest Gas objected
to the proposal’s exclusion of master
meter and LPG operators from the
requirement to install EFVs. They noted
that the PIPES mandate did not exclude
these operators. They also suggested
that these small operators do not have
the degree of control over excavations
that can cause damage, and thus over
the threat that EFVs are intended to
mitigate.
PHMSA response: In the NPRM, we
requested public comment on whether
we should limit the requirements
imposed on MM and LPG operators.
Although the PIPES Act mandate did
not exclude these operators from the
EFV installation requirement, we
proposed to exclude them from the
requirement because we expect few of
these lines will meet the threshold
performance requirements. Based on the
comments we received, we have reevaluated the proposal and determined
they should not be excluded. We agree
with commenters that the threshold
performance requirements are a better
means of excluding some systems than
just a blanket exclusion. Thus, in the
final rule, we have included master
meter and LPG operators among the
distribution operators subject to the
requirement to install EFVs.
As stated above, we expect that
because of the threshold performance

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standards required for EFV installation,
most of these simpler master meter and
LPG systems will not meet the threshold
and operators of these systems will
install few, if any, EFVs as a result of
this requirement. For example, many of
these systems operate at very low
pressures, and the rule provides that
EFVs need not be installed where
operating pressure is less than 10 psig.
f. Terminology.
One operator suggested that the
references to § 192.381 should refer to
‘‘performance standards’’ rather than to
performance requirements, as that
would be more accurate.
PHMSA response: PHMSA agrees and
has made this change.
Comment Topic 13: Guidance.
A number of comments addressed
guidance available for implementing
this rule.
a. PHMSA guidance.
AGA and several operators suggested
that the guidance document prepared by
PHMSA, and included in the docket, is
not necessary. They noted that the
GPTC Guidance for integrity
management (an appendix to the GPTC
Guide) is more complete and will be
available separately from the GPTC
Guide, at nominal cost. Iowa
commented that PHMSA’s guide is not
useful and that it conflicts with the
provisions in the rule concerning leak
management. One operator suggested
that the PHMSA guidance document
contains adequate detail for master
meter and LPG operators but that
references to requirements for larger
operators should be eliminated from it.
They commented that the document
does not accurately reflect reporting and
other requirements for larger operators.
PHMSA response: PHMSA agrees that
the GPTC appendix provides more
information than PHMSA’s draft
guidance. PHMSA is concerned,
however, that the GPTC appendix will
not be useful for most master meter and
small LPG operators. Many of these
operators will likely not purchase the
Guide or the separate appendix. The
appendix contains more information
than these operators need, and they
often lack the technical resources to
extract the more-limited information
that is important to their operations.
PHMSA considers it important to
provide guidance focused specifically
on the needs of MM/LPG operators and
will edit its guidance document to do
so. PHMSA will remove other
information and defer to the GPTC
appendix as guidance for larger
operators.
b. GPTC Guide.
GPTC and an industry consultant
noted that the preamble stated PHMSA

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would revise GPTC guidance if needed.
They point out that only GPTC can
change that guidance.
PHMSA response: The commenters
are correct. The statement in the NPRM
referred to potential changes PHMSA
might make to its own guidance for
MM/LPG operators, not to the GPTC
guidance.
Comment Topic 14: Leak monitoring.
A large distribution operator
suggested that the rule should not
require operators to ‘‘implement’’ leak
monitoring because that implies they do
not now have such programs. They
suggested that the rule require that
operators ‘‘have’’ such programs. The
operator also suggested that the rule
delineate the contents of an effective
program.
Several smaller operators suggested
that leak monitoring should not be
required in this rule at all. They
commented that only risk measures
indicated as appropriate by risk analysis
should be required.
APGA noted that some operators do
not monitor leaks; they repair all leaks.
APGA contended that these operators
should not be required to establish
criteria to grade leaks. Operators who do
not repair all leaks should have criteria
for grading leaks not repaired.
PHMSA response: Leakage is the
principal failure mode for low-stress
distribution pipelines. Most incidents
on distribution pipelines result from the
accumulation of gas that has leaked
from the pipeline. Section 192.703(c)
already requires that hazardous leaks be
repaired promptly, but operators may
repair leaks at a later time if determined
not to be hazardous. PHMSA considers
it important that operators monitor
these leaks to assure that hazardous
conditions do not develop. At the same
time, PHMSA recognizes that some
operators repair all leaks when found
and does not intend to require these
operators to develop unnecessary
monitoring programs. PHMSA also
recognizes that most operators that do
not repair all leaks when found already
have leak monitoring programs. PHMSA
has revised the final rule to require that
risk mitigation measures include a leak
monitoring program except if all leaks
are repaired when found. PHMSA has
also modified § 192.1007(e) to clarify
that operators who repair all leaks when
found do not have to categorize them for
hazard for the sole purpose of
performance monitoring.
PHMSA does not consider it
necessary to delineate the contents of an
effective leak management program in
the rule. Operators should develop a
program based on their knowledge of
their pipeline system. The GPTC Guide

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also offers guidance regarding how to
develop an effective leak management
program.
Comment Topic 15: State authority.
Florida PSC commented that States
must have the authority to review,
analyze, and approve or deny an
operator’s distribution IM program.
They contended that the programs will
be unique and complex. They noted that
evaluation of a program will require
judgment and suggested that reaching
an agreeable program may require
several years.
NAPSR commented that the rule
should explicitly recognize the need to
include flexibility for States to
accommodate their specific
circumstances. They noted that this
need was recognized explicitly in
PHMSA’s report to Congress on DIMP.
PHMSA response: Certified state
regulators who exercise jurisdiction
over intrastate distribution pipeline
operators have the authority and
obligation to inspect operator
compliance with this final rule;
however, PHMSA does not require an
operator’s plan to be approved by the
regulatory authority. Regulators must
review operator IM programs and direct
changes in cases in which they
determine that the operator’s program
does not comply with the rule. PHMSA
recognizes that IM programs will be
unique and can be complicated
(reflecting complexity in some
distribution systems) and that these
programs will likely take several years
to reach maturity. As noted earlier,
PHMSA plans to develop and provide
training and qualification programs for
state inspectors. PHMSA intends to
provide states with background
information necessary for them to
conduct reviews and to avoid large
inconsistencies in the approach to IM
across the country.
PHMSA’s statements in this
rulemaking record have consistently
recognized that states must have the
flexibility to address their specific
circumstances. Nothing in the language
of the rule restricts this flexibility.
PHMSA understands that operator IM
programs will vary based on differences
in their pipelines and operations and
that states need to consider each
program on its merits. The rule
establishes high-level requirements but
leaves operators and their regulators
(mostly states) to determine how best to
do it in each individual circumstance.
Comment Topic 16: IM program
evaluation and improvement.
A number of comments addressed
proposed requirements to evaluate and
improve distribution IM programs.
a. Continual evaluation.

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APGA, Iowa, and a number of
operators objected to the proposed
requirement in § 192.1007(f) that an
operator ‘‘must continually re-evaluate
threats and risks on its entire system.’’
These commenters suggested that such
re-evaluation be required on a periodic
basis. They noted that continuous reevaluation is unreasonable and that it
doesn’t follow from the concept of
‘‘periodic evaluation and improvement’’
(the title of this proposed paragraph).
PHMSA response: PHMSA considers
that operators should evaluate the
effectiveness of their IM programs on a
routine basis, i.e., ‘‘continually.’’ That is
a basic concept of an effective IM
program that has been used in other IM
regulations. Nonetheless, because of the
overwhelming concern raised by
commenters about this term, PHMSA
has revised the final rule to require that
such re-evaluations occur on a periodic
basis, based on the complexity of the
system and changes in factors affecting
the risk of failure; however, reevaluations must occur at least once
every 5 years.
b. Continuous improvement.
One operator noted that making
changes solely to show ‘‘improvement’’
can be disruptive and ultimately
detrimental to performance.
PHMSA response: Continuous
improvement is an important part of the
philosophy underlying IM. Where
evaluation of an IM program identifies
changes that can improve the program’s
effectiveness, these changes should be
incorporated into the program. The
ultimate goal is to improve safety.
Improvement cannot be realized
without change.
c. Evaluation frequency.
NAPSR objected to the proposed
requirement that operators must
determine the appropriate period for
conducting complete program
evaluations based on the complexity of
their systems and changes in factors
affecting the risk of failure and that the
interval selected may not exceed five
years. NAPSR suggested that an
evaluation be required annually (not to
exceed 15 months), similar to the
evaluation interval for other programs
required by Part 192. NAPSR believes
that five years is too long, noting that
the stakeholder conclusion was that an
annual review should be required.
PHMSA response: An operator should
re-evaluate its IM program whenever
changes occur in the system that may
result in new knowledge, new threats or
other information that would permit
improvement in the IM program. For
some operators, this may be more
frequent than an annual basis. For other
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occur seldomly. Therefore, we are
retaining the requirement for all
operators to evaluate their program at a
period appropriate for their system and
at least every five years, as proposed in
the NPRM.
d. Required improvement at specific
frequency.
Several operators objected to the
proposed requirement to periodically
improve each IM element in
§ 192.1005(b) (as well as the
requirement to continually refine and
improve in proposed § 192.1007(a)(4)).
They maintained it may not be
reasonable to ‘‘improve’’ all elements at
all times, and that enforcement of such
a requirement would pose problems.
They suggested that the proposed
requirements to ‘‘improve’’ be replaced
with a requirement to review and
adjust/update as needed to meet
distribution IM goals. One operator read
proposed § 192.1007(d) to require that
operators implement new mitigation
measures annually and requested we
clarify that this is not required.
PHMSA response: PHMSA’s intent
was to encourage operators to consider
potential improvements to their IM
programs routinely as a regular part of
their activities. To improve clarity,
PHMSA has revised the final rule to
require that programs be reviewed on a
periodic basis and improved as needed.
Section 192.1007(d) requires that
operators determine and implement
measures to reduce risks. Section
192.1007(f) requires that operators
reassess their programs periodically, but
at least every five years. Nothing in the
rule requires that new mitigation
measures be implemented at any
periodicity.
e. Redundant requirements.
One operator suggested we delete the
proposed requirement in § 192.1005(b)
that operators have procedures for
‘‘periodically improving each of the
required elements’’. The operator noted
that periodic evaluation and
improvement is, itself, an element, and
that this makes the proposed
requirement in § 192.1005(b) confusing,
at best.
PHMSA response: PHMSA agrees and
has revised the final rule. We have
revised section 192.1005 to specify that
an operator must develop and
implement a written IM program that
addresses the required elements in
§ 192.1007. Section 192.1007 now
provides that the IM plan must have
procedures to develop and implement
the required elements. One of the
required elements is to refine and
improve the program as needed (section
192.1007(a)(4)).

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f. Consideration of threats in reevaluation.
Another operator suggested that
PHMSA delete the requirement in
proposed § 192.1007(f) that an operator
‘‘consider the relevance of threats in one
location to other areas’’ as part of its
periodic re-evaluation. This operator
contended that this is covered by the
requirement in proposed § 192.1007(c)
that threats be considered in all areas.
PHMSA response: PHMSA recognizes
that a thorough evaluation of threats in
any area should identify threats of
concern regardless of whether they
affect other areas of an operator’s
system. Still, PHMSA considers that
knowledge that a threat affects a system
in one location, and how that threat
manifests itself, can inform
consideration of that threat in other
locations. PHMSA has retained this
requirement in the final rule.
Comment Topic 17: Permanent
marking of plastic pipe.
The NPRM preamble posed a number
of questions concerning permanent
marking of plastic pipe. These questions
elicited a number of responses.
a. Support for marking
One operator strongly supported
requirements to mark plastic pipe,
providing a list of attributes the operator
believes should be marked every 18
inches.
b. Against marking
AGA, supported by at least one
operator, suggested that plastic pipe
marking should be considered outside
of DIMP. Both maintained that
manufacturer input is needed on this
subject and that most operators do not
possess the data infrastructure to record
and properly manage data from each
piece of plastic pipe. They contended
that the knowledge requirements of
proposed § 192.1007(a) are sufficient to
manage pipeline integrity.
Several operators suggested that
ASTM should address pipe marking and
that PHMSA should not establish
requirements in this area. Some
operators, GPTC, Iowa and one plastic
pipe consulting company noted that the
current version of ASTM D2513, which
is not yet referenced in Part 192,
includes permanent marking
requirements. Some operators noted that
fittings are a separate concern and
suggested that they would present other
problems/considerations.
PHMSA response: We did not propose
a requirement to mark plastic pipe.
Rather, we asked for comment to elicit
better information about various pipe
types and their performance history.
PHMSA believes operators may be able
to better manage risk with better
information regarding pipe

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performance. We plan to address this
issue outside this rulemaking.
Comment Topic 18: Continuing
surveillance.
Iowa and a large operator suggested
that we revise § 192.613, Continuing
surveillance, to exclude distribution
systems subject to proposed new
Subpart P because it will be a redundant
and unnecessary requirement if DIMP is
implemented as proposed.
PHMSA response: PHMSA disagrees.
While some aspects of IM may overlap
activities operators perform as part of
continuing surveillance, there are
requirements in § 192.613 that are not
duplicated in this rule. For example,
DIMP does not specifically require an
operator to recondition or phase out an
unsatisfactory segment when no
immediate hazard exists.
Comment Topic 19: Information
gathering.
The NPRM proposed (§ 192.1007(a))
that an operator must demonstrate an
understanding of the gas distribution
system. NAPSR suggested that the
proposed rule should require operators
to assemble information about their
systems that is ‘‘reasonably available.’’
NAPSR maintained that it is
unreasonable to suggest operators
should develop the best understanding
possible. NAPSR further maintained
that the proposed language fails to list
useful sources of information and
implies an unbounded need for
knowledge. NAPSR would revise the
language to more completely identify
the sources of information to be used
and would limit the requirement to
identify system characteristics and
environmental factors (proposed subparagraph (a)(1)) to those ‘‘reasonably’’
necessary to assess threats and risks.
PHMSA response: PHMSA
understands NAPSR’s concern. PHMSA
does not intend that operators expend
excessive effort, review every record
available in their archives, or explore
every nuance about their pipelines. At
the same time, PHMSA expects that
operators will devote sufficient effort to
develop as thorough an understanding
of their pipelines as they can while
using reasonable effort. PHMSA has
revised the final rule to require that
operators develop an understanding of
their pipeline systems ‘‘from reasonably
available information.’’ PHMSA
considers that this strikes the
appropriate balance. Because of this
change, PHMSA does not consider it
necessary to modify subparagraph (a)(1)
to limit information to assess threats
and risk to ‘‘reasonably’’ necessary
information.
PHMSA has not included in the rule
a list of information that operators

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should use to find information about
their pipeline systems. An operator is in
the best position to determine what
information is most relevant to its
system. PHMSA is concerned that any
such list would become limiting (i.e.,
operators and regulators would not
consider sources not included in the
list) or would create unnecessary
burdens (e.g., a perceived obligation to
review a source listed even though it
would not reveal useful information).
Comment Topic 20: Knowledge of
pipeline.
PHMSA also received other comments
regarding the need for an operator to
know its pipeline:
a. Environmental factors.
APGA, GPTC, and a large operator
suggested that we clarify
‘‘environmental factors’’ in
§ 192.1007(a)(1) to mean factors (e.g.,
washouts, landslides) that could pose a
hazard to the pipe as opposed to factors
that would make the environmental
consequences of accidents worse. They
noted that gas does not produce
significant environmental consequences
as would oil or other hazardous liquids.
PHMSA response: PHMSA concludes
that no change is needed. This
paragraph already refers to
‘‘environmental factors that are
necessary to assess the applicable
threats and risks to its gas distribution
pipeline’’ and does not refer to
consequences. PHMSA notes that
washouts and landslides are extreme
examples of ‘‘environmental factors’’
that might be of concern. Other
environmental factors that might need
to be considered include soil corrosivity
or location in an area likely to
experience a greater-than-normal
amount of excavation activity.
b. Normal activities.
One large operator suggested that the
‘‘normal activities’’ through which
operators are expected to glean
additional knowledge (proposed
192.1007(a)(3)) be specifically limited
to, ‘‘normal activities performed in the
construction, operations, and
maintenance of gas distribution systems
in accordance with the applicable
requirements of Part 192.’’
PHMSA response: PHMSA does not
consider this limitation necessary.
Operators are expected to take
advantage of opportunities to improve
system knowledge through any of their
normal activities, including those that
go beyond those activities specifically
required by Part 192. For example,
excavation that exposes the pipeline
system presents a significant
opportunity to learn additional
information, but few excavations are

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conducted specifically to comply with
Part 192 provisions.
c. Additional activities.
PA PUC would expand the list of
activities through which operators are
expected to gain additional knowledge
to include maintenance and
management policies in addition to past
design and operations (§ 192.1007(a)(2)).
They would revise proposed
§ 192.1007(a)(4) to replace the
requirement to ‘‘continually’’ refine and
improve knowledge with a requirement
to ‘‘develop an ongoing process by
which the operator’s knowledge of its
system will be refined and improved.’’
PHMSA response: PHMSA’s use of
‘‘operations’’ in this context was
intended in its broadest sense—
activities associated with operating the
system, including maintenance. This
comment indicates that it is possible to
read the proposed language as excluding
maintenance. PHMSA has modified the
final rule to reflect that information
gained from operations and
maintenance should be considered.
PHMSA considers the phrase
‘‘management policies’’ to be vague and
subject to misunderstanding and has not
included it in the final rule. Changes
associated with eliminating the
implication that operators must
‘‘continually’’ improve their knowledge
have been described above.
d. Design and operations information.
One operator would delete proposed
paragraph (a)(2), which would require
that an operator understand the
information gained from past design and
operations, because it is unclear how
compliance can be achieved or
demonstrated. Another operator would
add ‘‘design and operations’’ to the
requirement in proposed paragraph
(a)(1) to understand the system.
PHMSA response: PHMSA has
revised paragraph 192.1007(a)(2) to
require that operators consider lessons
from past design and operation
experience, rather than that they
‘‘understand’’ them. For example,
operators could involve maintenance
foremen/supervisors in their
information collection activities,
surveying them to ask about unusual
circumstances they have encountered in
their activities and/or asking them to
review resulting system descriptions
and identify any information they
believe useful that is not already
included. Good information only has an
effect when it is used. Compliance will
be reviewed by assuring that an operator
has implemented means to gather this
information and has considered the
information.
e. Terminology.

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An operator would change ‘‘piping
system’’ and ‘‘piping and
appurtenances’’ in paragraph (a)(5) to
‘‘pipeline’’ for consistency with the
definition of pipeline in § 192.3.
PHMSA response: PHMSA has made
the suggested change.
Comment Topic 21: Threat
identification.
Several changes were suggested to the
proposed requirement for operators to
identify threats in § 192.1007(b).
Paragraph (b) listed categories of threats
and potential sources of information an
operator must consider.
a. Data sources.
APGA would delete reference to ‘‘one
call experience’’ because the meaning of
this term is unclear and would add
nothing beyond the operator’s own
damage experience. One operator would
limit ‘‘incident history’’ as a data source
to incidents requiring reporting per
§ 191.3. Another operator suggested that
the list of threats be revised to match the
list in the annual report, noting that
there are minor inconsistencies in the
wording of the proposed requirement.
An operator suggested that ‘‘and any
other concerns that could threaten the
integrity of the pipeline’’ is unlimited
and thus unreasonable.
PHMSA response: Because relevant
information from one call experience
would overlap with the operator’s own
excavation damage experience, PHMSA
agrees that listing one-call as a source of
information for threat identification is
redundant and has made the suggested
change. The term incident, as used in
the regulations, is commonly
understood to refer to incidents as
defined in § 191.3. The list of categories
in this final rule is consistent with the
categories in the annual report. What
minor wording inconsistencies exist are
due to use of the list in a sentence
structure in the rule. PHMSA considers
the language regarding ‘‘any other
concerns’’ to be consistent with the
‘‘other’’ category of threats on the
annual report form.
b. Sources of information.
NAPSR and Iowa contended that the
proposed language unnecessarily
restricts sources of information an
operator may use (i.e., ‘‘An operator
must gather information from the
following sources’’). Instead, NAPSR
would require that an operator consider
sufficient data to identify existing and
potential threats and would identify the
proposed list as sources an operator
‘‘may include, as appropriate.’’
PHMSA response: PHMSA agrees and
has revised the paragraph to clarify that
the information sources an operator
must use to identify threats are not
limited to those listed.

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c. Third party damage.
A consultant noted that the threat of
third-party damage should not be as
significant for small operators as for
large because small operators exercise
better control and/or it is easier to patrol
their systems. At the same time, he
noted that his own analyses of small
systems (i.e., master meter) suggests that
threats other than third-party damage
may be as significant or more significant
for small operators than for large.
PHMSA response: Each operator will
be required to determine the relative
importance of threats for its distribution
pipeline as part of implementing this
final rule. An operator will be able to
factor in the degree of control it has over
its system when determining the
relative importance of threats. We have
not revised the language in the final
rule.
Comment Topic 22: Risk assessments.
Several comments addressed the
proposed requirements for risk
assessment in § 192.1007(c).
a. Subdividing a pipeline for risk
analysis.
NAPSR and one operator commented
that subdivision of a distribution system
for risk analysis may not be
geographical, as they believe the
proposed language implied. They noted
that similarity of characteristics and
environment may be more important
factors for subdividing analyses than
location. The operator suggested that
class location might be an appropriate
factor. Other operators suggested that
the concept of ‘‘regions’’ for analysis is
not clear and commented that the
suggestion for grouping by consistent
risk or actions be eliminated; they noted
that one cannot group by common risk
without analyzing risk first and that
suggesting otherwise results in circular
logic.
PHMSA response: PHMSA agrees that
subdividing a distribution pipeline
system for risk analysis could be done
on a basis other than geography.
PHMSA has modified the final rule to
clarify that geographic proximity is only
an example of how a region may be
defined, by inserting ‘‘e.g.,’’ before this
description and by adding another
example. PHMSA agrees that the
concept of creating regions for risk
analysis on the basis of reasonably
consistent risk results is circular logic
and has deleted this criterion.
b. Evaluate threats.
One operator suggested that the
requirement to evaluate threats as part
of the risk assessment be limited to
known threats because it is impossible
to rank the importance of ‘‘potential’’
threats.

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PHMSA response: PHMSA disagrees.
In many cases, ‘‘known threats’’ are
treated as threats that have resulted in
an effect on the pipeline, while other
threats are, at best, ‘‘potential.’’ For
example, earth movement might not be
considered a ‘‘known threat’’ for pipe
located in an area where landslides can
be expected but where the pipeline has
never been affected by one. It would be
important, though, to consider the
likelihood that the ‘‘potential’’ threat of
earth movement might affect this pipe
as part of an operator’s IM program. It
should also be possible to collect
information about the relative
likelihood of a landslide to consider this
threat, including ranking its importance
and determining whether mitigative
actions are appropriate. PHMSA has
retained the requirement to consider
potential threats in the final rule.
c. Defining terms.
One operator suggested that the term
‘‘relative probability’’ should be
defined. Another operator suggested
that the term ‘‘probability’’ be replaced
with ‘‘likelihood’’ throughout the
proposed rule, to eliminate the
implication a rigorous mathematical
process is required.
PHMSA response: PHMSA agrees that
use of the terms ‘‘probability,’’ ‘‘relative
probability,’’ and ‘‘prioritize’’ could
imply a need for a mathematical
process. PHMSA has noted confusion
about the need for quantified estimates
of risk throughout the discussions
related to distribution integrity
management. For complex systems
where there is a wealth of data, a
mathematical analysis of risk may be the
best way to understand the relative
importance of various threats. For most
distribution pipeline systems, however,
simpler techniques (as described in the
GPTC Guide, for example) should
suffice. PHMSA has revised the final
rule, to avoid further confusion, to
replace these terms with ‘‘importance,’’
‘‘relative importance,’’ and ‘‘rank.’’ One
useful reference tool could be the GPTC
Guide for guidance on nonmathematical methods of evaluating
risk.
d. Prioritize risk.
One operator suggested that the
requirement to estimate or prioritize risk
should be eliminated, and that the
requirement be limited to determining
the relative probability of threats. The
operator contended that each pipe
material carries its own threats, and that
it is difficult to prioritize one over
another. Prioritization is too difficult
and may not meet the intended purpose
because there is often insufficient data
to quantify.

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PHMSA response: PHMSA disagrees
with eliminating a requirement to
prioritize risk. Prioritizing actions is an
inherent part of managing any activity.
It is needed to apply limited resources
where they will do the most good. With
respect to IM, PHMSA firmly believes
that this prioritization should consider
risk, i.e., both likelihood and
consequences. For example, an operator
may face two threats that can produce
different consequences. It would be
inappropriate to apply resources to the
threat with a slightly higher likelihood
of occurrence and not to the second
threat if the consequences that could
result from the second threat are much
greater. The risk (i.e., likelihood and
consequences) of the second threat is
higher.
PHMSA understands that it is easier
to rank threats when only a single
variable changes, and that limiting
consideration to threat ranking by
material would be easier. This would
not, however, assure the most effective
application of safety resources, which
an operator must apply across its entire
pipeline, regardless of differences in the
material of construction.
Comment Topic 23: Performance
measures.
A number of comments were made
concerning proposed requirements for
performance measures. In the NPRM,
PHMSA proposed that an operator must
develop and monitor performance
measures to evaluate the effectiveness of
its IM program and required the
performance measures to include the
number of hazardous leaks, categorized
by cause and by materials, number of
excavation damages, the number of
excavation tickets, the number of EFVs
installed, and the total number of leaks
categorized by cause. The proposal
required an operator to develop
additional measures necessary to
evaluate the effectiveness of controlling
each identified threat.
a. NAPSR suggested an additional
performance measure, which could be
derived from data already reported: the
amount or ratio of non-state-of-the-art
pipe in an operator’s system.
PHMSA response: PHMSA does not
agree that this is an appropriate national
measure. This measure was considered
in the work of the stakeholder groups.
The final report of that work did not
recommend this as a national
performance measure.9 One reason for
this conclusion was that it could be
misleading. Much older pipe (e.g., cast
iron) that has been properly maintained
9 PHMSA, ‘‘Integrity Management for Gas
Distribution: Report of Phase 1 Investigations,’’
December 2005, page 16.

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operates quite safely. At the same time,
problems have sometimes been
experienced with new pipe (e.g.,
specific heats of plastic pipe). PHMSA
recognizes that many states are working
with their operators to support pipe
replacement programs intended to
replace non-state-of-the-art pipe, and
PHMSA encourages those efforts.
PHMSA expects that the states will
monitor the amount of non-state-of-theart pipe remaining in an individual
operator’s system as part of such
replacement programs. Reporting this
parameter on a national basis is not
needed to facilitate required pipe
replacement programs.
b. The proposed performance
measures included the number of
hazardous leaks eliminated or repaired
and the number of excavation tickets. A
consultant suggested the need for more
precise definitions of ‘‘ticket’’ and
‘‘leak’’ as the use of these terms is
imprecise across the industry. Two
operators agreed that a definition of
excavation ticket is needed. Another
suggested that this be limited to ‘‘tickets
received from the notification center
where marking is required.’’ Another
suggested that PHMSA should not
define this term.
An operator suggested that damages
should be normalized per 100 tickets.
The operator noted that differing levels
of construction activity could imply that
an operator’s IM program is more, or
less, effective but that this is totally
outside the operator’s control. Another
operator suggested that the number of
excavation tickets has no value as a
performance measure, and that this data
is expensive to generate. This operator
explained that tickets are often issued
for areas in which there is no gas pipe
in the vicinity of planned excavation
and that tickets may be renewed. These
operators also suggested that tickets are
issued for areas of differing size. They
contended that, because of all of these
differences, this data is not useful to
normalize excavation damage
information.
PHMSA response: The purpose of the
measure to report the number of
excavation tickets is to normalize
excavation damage information in order,
for example, to help determine whether
reduced excavation damages are a result
of improved damage prevention
programs or less construction
(excavation) activity. Normalization is
necessary precisely for the reason
identified by the commenters—changes
in the amount of construction activity
will affect the number of excavation
damages but are outside the control of
an operator’s IM program. PHMSA
expects that analyses will likely

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normalize per 100 tickets but notes that
this is a simple arithmetic adjustment if
the basic data is available. Operators are
required to participate in one-call
programs to receive notification of
planned excavation activity, i.e.,
tickets.10 PHMSA thus concludes that
collecting this data will not be
expensive. Reporting of this parameter
has thus been retained in the final rule.
Differences in how tickets are treated
and in the definition of ‘‘ticket’’ among
various state one-call programs were
discussed during the stakeholders’ work
preceding the proposed rule. The groups
noted that this term is defined
somewhat differently by various state
one-call programs, and that these
differences could cause inconsistencies
in data reported to PHMSA. At the same
time, the groups noted that considerable
additional effort could be required for
operators to track tickets in two ways—
one matching their one-call program
definition and one matching a common
national definition. The stakeholder
groups concluded that this data could
serve its purpose even if there were
some inconsistency in the data reported
to PHMSA and that the additional
burden involved for some operators
using two definitions was not justified.
PHMSA agrees. The final rule clarifies,
as did the proposal, that what is meant
by a ‘‘ticket’’ is receipt by the operator
of information from the notification
center, regardless of the criteria the
center uses to decide when notifications
should be made.
Leaks have been reported on the
annual report required of distribution
operators for many years. The
instructions for completing the annual
report define a leak as the unintentional
release of gas from a pipeline. PHMSA
is not aware of any difficulties or
confusion in reporting leaks, and does
not consider that a definition need be
added to this rule.
c. A consultant suggested that the
requirement for operators to measure
performance should be deleted.
Alternatively, PHMSA should evaluate
incidents against program effectiveness.
The consultant believes that individual
operators cannot generate enough data
for meaningful analysis and that
problems inherent in performing
statistical analysis of small numbers and
luck, both good and bad, would likely
obscure meaningful information from an
operator’s performance analyses. Two
commenters suggested that the
performance measures requirement be
eliminated. An operator suggested that
the rule should simply require that
10 49 Code of Federal Regulations, Section
192.614(b).

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operators have appropriate measures.
Iowa suggested that the requirements
are not needed if the annual report
forms are modified to include the
desired information.
The NPRM preamble noted that a
reduction of incidents will be the
ultimate indicator of performance, but
that it will take years to see trends in
this data. The NPRM stated that the
proposed performance measures would
provide a measurement during the
interim period while these trends are
developing and invited the public to
suggest other measures for this interim
period. In response, one operator
commented that there should be no
interim measures, only permanent.
Another operator, apparently reflecting
the same concern about potential
changes in reporting requirements,
suggested that performance measures,
once in place, should remain stable for
at least 5 years. The operators noted that
time is needed to determine the
effectiveness of such measures and to
implement data system changes and
personnel training.
PHMSA response: Measuring
performance is a key element of all
integrity management programs. IM
rules for other types of pipelines also
include this element. At its basic level,
IM is an iterative process consisting of
analysis of risks, implementing actions
to reduce risk, monitoring to evaluate
the effectiveness of those actions, and
modifying the program as needed.
Without performance monitoring, the
feedback portion of the process cannot
occur.
On a macro basis, PHMSA agrees that
the number of incidents is the ultimate
measure of the effectiveness of efforts to
assure distribution safety. PHMSA will
continue to collect incident data and
will use that data to evaluate the
effectiveness of its regulatory program.
This measure is not useful to individual
operators, however, precisely because
the number of incidents is small. Many
operators will experience no incidents
in a year. Few, if any, will experience
more than one. Operators must use
other non-incident measures to evaluate
the effectiveness of their own programs.
PHMSA continues to conclude that it is
appropriate that the rule require these
actions.
As discussed in the NPRM, it will
take several years for incident data to
indicate any trend as a result of the
actions required by this rule. PHMSA
considers it necessary to collect
additional performance measures to
permit preliminary judgments
concerning the effectiveness of this
regulation in the interim. This does not
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‘‘permanent.’’ The final rule retains the
requirement to submit performance
measures in the annual report.
d. A citizens group commented that
key information, such as hazardous
leaks repaired by cause and material,
must be publicly available. NAPSR and
the Pennsylvania PSC also suggested
that data reported to PHMSA should be
in a database accessible to states, rather
than requiring duplicate reporting. The
Arizona Corporation Commission,
taking a contrary position, suggested
that reports sent to PHMSA should also
be required to be submitted to States
exercising jurisdiction.
PHMSA response: All IM performance
measures submitted to PHMSA will be
part of the annual report filed by
distribution pipeline operators. Annual
report information is available to the
public via the PHMSA web site. In
addition, we are requiring operators to
report performance measure information
to states exercising jurisdiction.
e. NAPSR and Iowa suggested that the
number of leaks repaired/replaced by
material be added as a national
performance measure, as this is useful
information relevant to the effectiveness
of IM. These commenters also suggested
that the requirement to report
information concerning leaks be limited
to information that is known or
available. They noted that operators
may not excavate leaking pipe, but may
replace it and retire leaking sections in
place. In that instance, they may not
know the cause of the leak, or the
particular material on which it occurred
(e.g., whether on pipe body or a valve/
fitting).
PHMSA response: The stakeholder
groups considered the use of leaks-bymaterial as a national performance
measure but rejected it as a measure in
part because of the potential for
misinterpretation. Many leaks are
caused by excavation damage or other
outside forces, in which case the pipe
material is not of principal importance.
The groups concluded that this would
be useful information for operators in
evaluating the effectiveness of their own
programs but that it should not be
reported on a national basis. PHMSA
agrees.
PHMSA notes that operators have
been required to report the number of
leaks eliminated/repaired, by cause, for
many years as part of their annual
reports. Operators have presumably
filed these reports based on the
information that they have available.
PHMSA is not aware of complaints that
unnecessary effort has been required
simply to determine a cause for
reporting purposes. PHMSA therefore
does not consider that any explicit

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limitation is necessary on the
information to be used to identify the
cause of repaired leaks.
f. An operator suggested that specific
causes to which leaks are to be
attributed should be listed, and further
that the list of causes must include
‘‘unknown.’’ The operator suggested
that meaningful comparisons require a
limited number of specified causes. The
operator also noted that lines are often
retired in place rather than being
removed, and that the cause of leaks is
thus not always known.
PHMSA response: Performance
reporting will be via the annual report.
The annual report currently requires
that operators report leaks repaired by
cause. It lists a number of causes for this
purpose, including ‘‘other.’’ Any
revisions to the form for purposes of IM
performance measures will similarly
provide a list of causes. See the annual
report comment topic for more
information regarding changes to the
annual reporting form.
g. NAPSR, Iowa, and one operator
suggested that we clarify ‘‘any
additional measures’’ described in
proposed § 192.1007(e)(1)(vii) are
additional measures the operator
selects.
PHMSA response: PHMSA has made
this clarification.
h. One operator suggested that
PHMSA should establish guidance for
implementing uniform metrics, since
these are needed for a performancebased process.
PHMSA response: PHMSA will use
four measures to evaluate the overall
effectiveness of this regulation. These
measures are specified in this rule, will
be listed on the revised annual report
form, and will be in the instructions for
completing the annual report. As
discussed above, PHMSA expects that
there will be some inconsistencies in
reporting of at least one measure
(number of excavation tickets); however,
the data submitted with the annual
report will be sufficient for PHMSA to
evaluate the effectiveness of the
regulation.
PHMSA does not consider that further
guidance is necessary to assure that
operators are collecting other
performance measure data uniformly, as
that data will be used by individual
operators to evaluate the effectiveness of
their programs. An individual operator
should collect and use the data it
collects consistently; however,
differences between operators do not
matter.
Comment Topic 24: Regulatory
analysis.
We received a number of comments
concerning the regulatory analysis

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supporting the proposed rule: In
response to a question about whether
the proposed performance measures
were burdensome, two commenters
stated they were not. Other commenters
raised specific issues regarding the
regulatory analysis.
a. Assumptions used in the analysis.
NAPSR, AGA, an operator
association, and an individual operator
commented that assumptions made in
the analysis are not supported. In
particular, the assumption that
implementing the proposed rule will
result in a 50 percent reduction in
incidents, which is key to the analysis
of the benefits of the proposal, appears
to have no foundation.
PHMSA response: It is not possible to
determine precisely the effectiveness of
a new regulation before it is
implemented. It is therefore necessary to
make assumptions for purposes of
analysis. The analysis then includes an
evaluation of the sensitivity of its
conclusions to those assumptions. Here,
PHMSA expects that the regulation will
help ensure the integrity of distribution
pipelines and will reduce the number
and severity of incidents that occur on
these pipelines. An assumption of a 20
percent to 50 percent reduction in
incidents was made for purposes of
analysis, but that assumption is not
critical to the conclusions. The final
regulatory impact analysis
demonstrates,11 in fact, that societal
costs associated with gas distribution
need only be reduced by about 12.2
percent in the first year and 9.5 percent
in successive years for the rule to yield
positive net benefits.
b. Lost gas.
AGA and an operator noted that
assumptions concerning lost gas are not
supported. They refer to the stakeholder
report where the difficulties of
measuring lost gas are discussed. That
report states that reported ‘‘lost gas’’
often reflects measurement uncertainties
rather than actual losses.
PHMSA response: Whether the
amount of lost gas can be measured with
accuracy does not affect whether gas is
actually lost. PHMSA understands that
the amount of lost gas reported may
depend as much on measurement
uncertainties as on actual losses, but
concludes that actual loss does occur.
This rule will have the effect of
improving leak management, and
damage prevention. The requirement
that excess flow valves be installed will
reduce the amount of gas released if a
service line is damaged by excavation.
All of these actions will reduce the
11 Final Regulatory Impact Analysis, ‘‘Summary
and Conclusions’’, p. 61.

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amount of gas lost. PHMSA has relied
on information from the EPA for its
assumptions concerning lost gas, and
considers that the estimated reduction
of 10 percent cited in the regulatory
impact analysis is reasonable.
c. Competitive market.
AGA, an operator association, and an
operator disagreed with our conclusion
that local gas distribution is not a
competitive market. They noted that
utility commissions consider all market
forces and that some States have
deregulated this function.
PHMSA response: PHMSA recognizes
that utility regulatory commissions
consider market forces in their rate
regulating activities and that some
aspects of natural gas supply have been
deregulated in some States.
Nevertheless, distribution of natural gas
has not been completely deregulated in
any areas of which PHMSA is aware—
i.e., a customer does not have a choice
of multiple suppliers for natural gas
delivered to its residence or place of
business. Thus, PHMSA considers that
the statement made was accurate. It did
not affect the conclusions of the
analysis.
d. Cost effective.
FL PSC suggested that the proposal is
not cost effective, noted that recent
regulatory extensions have been
extensive, and suggested we review the
current regulations, in total, before
proposing more. They pointed to a rate
case in which a company is requesting
$750,000 to implement distribution IM
for a system containing 10,000 miles of
distribution mains, and that applying
the unit rate to the total mileage of
distribution mains in the U.S. would
result in an estimated implementation
cost of nearly $84 million. This would
equate to more than $3.8 million per
death averted if all deaths resulting from
accidents on distribution systems could
be eliminated, which they contend is
not a practical assumption. FL PSC also
commented that State regulators are
overburdened and cannot do more than
they are now.
PHMSA response: It is unclear what
basis an operator would have used for
a rate case addressing implementation
of distribution IM at the time of the
NPRM, since requirements for that
purpose were not final. This final rule
makes significant changes from the
NPRM, most of which will have the
effect of reducing costs. PHMSA has
analyzed the costs and benefits that are
expected to result from this final rule
and has concluded that the rule is costbeneficial.
PHMSA recognizes that State
regulatory programs will be required to
undertake new work as a result of this

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63923

rule. PHMSA supports State pipeline
safety programs through grants and is
increasing the level of that support.
States exercise regulatory authority over
intrastate pipelines once they are
certified by PHMSA to do so.
e. Burden hour estimate.
A consultant noted that the estimate
in the regulatory analysis of @ hour for
master meter operators to update their
programs is unrealistic. He believes that
4 hours is a better estimate for such an
update.
PHMSA response: The regulatory
analysis and the paperwork reduction
act burdens have been recalculated
based on comments to the NPRM.
PHMSA has revised the estimate to
twelve hours per year for master meter
operators to update their programs.
Comment Topic 25: IM for new
pipelines.
The Missouri Public Service
Commission noted that the proposed
rule provides many requirements to
address the integrity of existing
distribution pipeline systems but is
silent on the need to assure integrity for
new installations. Missouri suggested
the rule address how well a pipeline
system is built/constructed/installed,
which is critical to its integrity.
Missouri also suggested adding
increased inspection requirements for
contractors performing new installations
to assure the integrity of new pipelines
being installed, and to not install
pipelines today that will create integrity
issues in the future.
PHMSA response: PHMSA agrees that
good installation/construction is
important to assuring pipeline integrity.
This proposal, however, deals with
assuring the integrity of existing
pipeline systems. Construction is
addressed by other regulations for
which changes were not proposed as
part of this rulemaking. PHMSA may
consider changes to construction
regulations as part of future rulemaking
activities.
Comment Topic 26: Annual report
form.
One operator suggested that PHMSA
should develop its reporting forms by
working in conjunction with AGA and
APGA.
PHMSA response: All data required to
be reported will be reported via the
annual report. PHMSA has revised the
annual report form using its normal
procedure, which included consultation
with the trade associations.
This final rule requires operators to
report four integrity management
performance measures as part of the
annual report. The rule also requires
operators to report, as part of the annual
report, detailed information regarding

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compression coupling failures. One of
the performance measures—total
number of leaks eliminated or repaired,
categorized by cause—is already a part
of the annual report form; however, the
other information to be reported will
require modifications to the annual
report form. Therefore, PHMSA is
issuing, in conjunction with this
rulemaking, a 60-day notice to modify
the annual report information
collection, OMB Control Number 2137–
0522. PHMSA seeks comment on the
proposed modified annual report form.
III. National Transportation Safety
Board
The National Transportation Safety
Board (NTSB) is an independent agency
that investigates major transportation
accidents, including those occurring on
pipelines. The NTSB makes
recommendations to PHMSA when it
concludes from investigation of pipeline
accidents that additional regulatory
actions would be appropriate to
improve safety.
The NTSB submitted comments on
this rulemaking on November 19, 2008.
The NTSB supported the approach to
distribution IM being taken by PHMSA
and stated that ‘‘overall, the NPRM
provides a reasonable and logical
approach that operators of distribution
pipelines can use to develop and
implement integrity management
plans.’’ The NTSB also identified three
areas in which they concluded the
proposed rule should be improved.
The NTSB considers that an effective
leak management program, as required
in this rule, must provide for use of
equipment that prevents or mitigates
leaks. The Board sees EFVs as
equipment that should be used for this
purpose. The NTSB acknowledges that
the proposed rule’s requirements for
installation of EFVs implement the
mandate in the PIPES Act of 2006, but
considers that it should go farther. The
NTSB recommends that the rule require
the installation of EFVs on all new and
replaced customer service lines,
regardless of customer classification.
This would include multi-family
dwellings (e.g., apartment buildings)
and commercial properties. This is
consistent with a recommendation the
NTSB made in 2001 following
investigation of a pipeline accident.
We have considered requirements for
installation of EFVs for many years.
PHMSA has conducted two cost-benefit
studies. These studies reached contrary
conclusions on whether a requirement
to install EFVs was cost beneficial and
demonstrated that the conclusion on
whether EFV installation is costbeneficial is highly sensitive to the

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assumptions and data used in the
analysis. The PIPES Act required that
PHMSA include in this final rule a
requirement to install EFVs on new and
replaced service lines serving singlefamily residences. This addresses the
vast majority of gas distribution service
lines, and this requirement has been
included in this final rule. PHMSA has
not studied separately the required
installation of EFVs on properties other
than single-family residences and is
uncertain whether such a requirement
can be justified on a cost-benefit basis.
The arguments for installing EFVs are
that they are effective in preventing
accidents caused by significant damage
to a downstream service line and that
they are inexpensive to install (when
the line is newly installed or excavated
for other reasons). The contrary
argument is that an EFV protects only
the service line in which it is installed
and incidents causing significant
damage to a service line are rare. Thus,
a large number of EFVs must be
installed, at a large cumulative expense,
before one can say with confidence that
it is likely that the presence of the
installed valves will prevent an
accident.
The potential consequences of
accidents involving service line damage
at multi-family or commercial
properties are likely larger than those
that would result from accidents on a
service line serving a single-family
residence. The likelihood that an
individual service line would be
damaged remains, however, small, and
the likelihood that an EFV would
prevent an accident at an individual
installation is correspondingly small.
There are far fewer multi-family and
commercial properties than there are
single-family residences. This could
reduce the likelihood that an EFV
would be expected to prevent an
accident at such a property so that a
cost-benefit analysis would conclude
that requiring installation of the valves
is not justified. Before imposing such a
requirement, PHMSA would need to
collect data from manufacturers of larger
EFVs and from operators who currently
install such valves and conduct a
detailed cost-benefit analysis. These
actions have not been completed, and
PHMSA has not expanded the
requirement in this final rule beyond
the mandate in the PIPES Act.
The NTSB also recommended that the
final rule be revised to address more
explicitly the risks from compression
couplings. The Board noted that it has
investigated a number of accidents
caused by pipe pulling out of
compression couplings, and that several
states have taken actions to require

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replacement or other actions to assure
that compression coupling joints are
safe. The NTSB recommended that the
rule include specific guidance on how
to identify and address problem
compression couplings.
PHMSA agrees that there are reasons
for concern regarding compression
couplings. PHMSA issued an advisory
bulletin on this subject on February 28,
2008. The NTSB acknowledged that this
bulletin should help utilities identify
future problems, but expressed concern
that it is only advisory and that
operators are not required to implement
its suggestions.
PHMSA will encourage GPTC to
review its guidance with respect to
compression couplings and to improve
that guidance, if needed. PHMSA has
revised this final rule to require that
operators report information on
coupling failures as part of their annual
report to PHMSA (see comment topic 1
above). PHMSA will consider the data
from these reports to decide whether
additional requirements relative to
compression couplings are warranted.
Any additional requirements related to
compression couplings would be
outside the scope of the proposed rule.
Finally, the NTSB recommended that
the rule include specific requirements
that operators address risks from
directional drilling. PHMSA has not
made this change for the same reasons
as described above for compression
couplings. Directional drilling is a type
of excavation damage, a threat category
operators are required to consider. We
expect that GPTC will provide guidance
on considering the threat of directional
drilling.
IV. Advisory Committee
On December 12, 2008, PHMSA
discussed the proposed rule with the
Technical Pipeline Safety Standards
Committee (TPSSC). The TPSSC is a
statutorily mandated advisory
committee that advises PHMSA about
the technical feasibility, reasonableness
and cost-effectiveness of its proposed
regulations. PHMSA discussed some of
the key comments received in response
to the NPRM, e.g., burdensome
documentation requirements,
performance through people, plastic
pipe failure reporting and excess flow
valves. These comments have been
previously discussed in this document.
After careful consideration, the
TPSSC voted unanimously to find the
NPRM (with proposed changes as
discussed at the meeting) and
supporting regulatory evaluation
technically feasible, reasonable,
practicable, and cost effective. A
transcript of the teleconference is

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available in the docket for this
rulemaking. The following tables

63925

summarize the major changes discussed
at the meeting.

NPRM language

TAC recommendation

Final rule language

Burdensome Plan Documentation Requirements
§ 192.1015 What records must an operator
keep?
Except for the performance measures records
required in § 192.1007, an operator must
maintain, for the useful life of the pipeline,
records demonstrating compliance with the
requirements of this subpart. At a minimum,
an operator must maintain the following
records for review during an inspection:
(a) A written IM program in accordance
with § 192.1005;
(b) Documents supporting threat identification;
(c) A written procedure for ranking the
threats;
(d) Documents to support any decision,
analysis, or process developed and
used to implement and evaluate each
element of the IM program;
(e) Records identifying changes made to
the IM program, or its elements, including a description of the change and the
reason it was made; and
(f) Records on performance measures.
However, an operator must only retain
records of performance measures for
ten years.

Limit documentation requirements to those in
§ 192.1005 and § 192.1007
Greatly reduce requirements in § 192.1015;
focus on wording similar to § 192.1015(e)
Clarify requirement to retain record of past
versions of written IM program
Language:
§ 192.1015 What records must an operator
keep?
(a) General records. Operator must maintain
records demonstrating compliance with the
requirements of this subpart for 10 years.
This must include copies of superseded IM
plans.

§ 192.1011 What records must an operator
keep?
An operator must maintain records demonstrating compliance with the requirements
of this subpart for at least 10 years. This
must include copies of superseded integrity
management plans developed under this
subpart.

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

Delete requirement
Continue to rely on PPDC
Promote broad communication of more expansive set of PPDC lessons
Retain reporting of compression couplings failure
Language:
§ 192.1009 What must an operator report
when compression couplings fail?
Each operator must report information relating
to each failure of compression couplings annually by March 15, to PHMSA as part of
the annual report required by § 191.11 beginning with the report submitted March 15,
20xx [Date to depend on when final rule is
issued].

§ 192.1009 What must an operator report
when compression couplings fail?
Each operator must report, on an annual
basis, information related to failure of compression couplings, excluding those that result only in non-hazardous leaks, as part of
the annual report required by § 191.11 beginning with the report submitted March 15,
2011. 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, coupling manufacturer, lot number and date of manufacture, and other information that can be
found in markings on the failed coupling. An
operator also must report this information to
the state pipeline safety authority if a state
exercises jurisdiction over the operator’s
pipeline.

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Performance Through People
(b) 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.

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Delete requirement, including reference to
‘‘one call.’’
Language:
(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 an effective
leak management program (unless all leaks
are repaired when found) and a damage
prevention
program
required
under
§ 192.614 of this part.

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Requirement deleted, including reference to
‘‘one call.’’
(d) Identify and implement measures to address risks. Determine and implement
measures designed to reduce the risks from
failure of its gas distribution pipeline. These
measures must include an effective leak
management program (unless all leaks are
repaired when found).

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Federal Register / Vol. 74, No. 232 / Friday, December 4, 2009 / Rules and Regulations
NPRM language

TAC recommendation

Final rule language

(d) Identify and implement measures to address risks. Determine and implement measures designed to reduce the risks from failure of its gas distribution pipeline system.
These measures must include implementing
an effective leak management program and
enhancing the operator’s damage prevention
program required under § 192.614 of this
part. To address risks posed by inappropriate operation, an operator’s written IM
program must contain a separate section
with a heading ‘Assuring Individual Performance’. In that section, an operator must list
risk management measures to evaluate and
manage the contribution of human error and
intervention to risk (e.g., changes to the role
or expertise of people), and implement
measures appropriate to address the risk. In
addition, this section of the written IM program must consider existing programs the
operator has implemented to comply with
§ 192.614 (damage prevention programs);
§ 192.616 (public awareness); Subpart N of
this Part (qualification of pipeline personnel),
and 49 CFR Part 199 (drug and alcohol testing).

(f) Periodic Evaluation and Improvement. An
operator must continually re-evaluate
threats and risks on its entire system and
consider the relevance of threats in one location to other areas. In addition, each operator must periodically evaluate the effectiveness of its program for assuring individual performance to reassess the contribution of human error to risk and to identify opportunities to intervene to reduce further the human contribution to risk (e.g., improve targeting of damage prevention efforts). Each operator must determine the
appropriate period for conducting complete
program evaluations based on the complexity of its system and changes in factors
affecting the risk of failure. An operator
must conduct a complete program reevaluation at least every five years. The operator
must consider the results of the performance monitoring in these evaluations.

(f) Periodic Evaluation and Improvement. An
operator must re-evaluate threats and risks
on its entire pipeline and consider the relevance of threats in one location to other
areas. Each operator must determine the
appropriate period for conducting complete
program evaluations based on the complexity of its system and changes in factors
affecting the risk of failure. An operator
must conduct a complete program reevaluation at least every five years. The operator
must consider the results of the performance monitoring in these evaluations.

Definition of ‘‘Damage’’
Damage means any impact or exposure resulting in the repair or replacement of an underground facility, related appurtenance, or materials supporting the pipeline.

Define ‘‘excavation damage’’ building on the
definition in DIRT—increases clarity of reporting requirement.
Language:
Excavation Damage means any impact or exposure that results in the need to repair or
replace an underground facility due to the
weakening or the partial or complete destruction of the facility, including, but not
limited to, the protective coating, lateral support, cathodic protection or the housing for
the line device or facility.

Excavation Damage means any impact that
results in the need to repair or replace an
underground facility due to a weakening, or
the partial or complete destruction, of the
facility, including, but not limited to, the protective coating, lateral support, cathodic protection or the housing for the line device or
facility.

Implementation Requirements

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§ 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 June 6, 2011 an operator of a gas distribution pipeline must develop and fully implement a written IM program. The IM program must contain the elements described in § 192.1007.
(b) Procedures. An operator’s program must
have written procedures describing the processes for developing, implementing and periodically improving each of the required elements.

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Retain same period
Language:
§ 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 June 6, 2011 an operator of a gas distribution pipeline must develop and fully implement a written IM program. The IM program must contain the elements described in § 192.1007.
(b) Procedures. An operator’s program must
have written procedures for developing, implementing and periodically improving the
required elements.

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§ 192.1005 What must a gas distribution operator (other than a master meter or small
LPG operator) do to implement this subpart? No later than August 2, 2011 a gas
distribution operator must develop and implement an integrity management program
that includes a written integrity management
plan as specified in § 192.1007.

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Final rule language

Alternative Intervals for Periodic Actions

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§ 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.

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Clarify intent as to responsibility for decision
on waiver requests (States approve, no
PHMSA review)
Need to make sure that it is clear that overall
level of safety is increased—not the level of
safety on that particular line is equal or
higher.
System level rather than individual line.
Language:
§ 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, in the case of an intrastate pipeline facility regulated by the State,
the appropriate State agency. The applicable state oversight agency may accept the
proposal on its own authority, with or without conditions and limitations, on a showing
that the adjusted interval provides a satisfactory level of pipeline safety.

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§ 192.1013 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.
(b) An operator must submit its proposal to
the PHMSA Associate Administrator for
Pipeline Safety or, in the case of an intrastate pipeline facility regulated by the State,
the appropriate State agency. The applicable oversight agency may accept the proposal on its own authority, with or without
conditions and limitations, on a showing that
the operator’s proposal, which includes the
adjusted interval, will provide an equal or
greater overall level of safety.
(c) An operator may implement an approved
reduction in the frequency of a periodic inspection or test only where the operator has
developed and implemented an integrity
management program that provides an
equal or improved overall level of safety despite the reduced frequency of periodic inspections.

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Program Requirements for Master Meters and LPG Operators

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(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.

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Retain separate treatment; revise wording to
include the requirement to ‘‘rank risks’’
Language:
(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) Rank risks. The operator must evaluate
the risks to its system and estimate the relative importance of each identified threat.
(4) 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.
(5) 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.
(6) 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.

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(1) Knowledge. The operator must demonstrate knowledge of its pipeline, which, to
the extent known, should include the approximate location and material of its pipeline. The operator must identify additional
information needed and provide a plan for
gaining knowledge over time through normal activities conducted on the pipeline (for
example, design, construction, operations or
maintenance 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 failure, and incorrect operation.
(3) Rank risks. The operator must evaluate
the risks to its pipeline and estimate the relative importance of each identified threat.
(4) Identify and implement measures to mitigate risks. The operator must determine
and implement measures designed to reduce the risks from failure of its pipeline.
(5) Measure performance, monitor results, and
evaluate effectiveness. The operator must
monitor, as a performance measure, the
number of leaks eliminated or repaired on
its pipeline and their causes.
(6) Periodic evaluation and improvement. The
operator must determine the appropriate period for conducting IM program evaluations
based on the complexity of its pipeline 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.

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NPRM language

TAC recommendation

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Final rule language

Excess Flow Valve Requirement
§ 192.1011 When must an Excess Flow Valve
(EFV) be installed?
(a) General requirements. This section only applies to new or replaced service lines serving
single-family residences. An EFV installation
must comply with the requirements in
§ 192.381.
(b) Installation required. The operator must install an EFV on the service line installed or
entirely replaced after March 4, 2010, unless
one or more of the following conditions is
present:
(1) The service line does not operate at a
pressure of 10 psig or greater throughout the year;
(2) The operator has prior experience with
contaminants in the gas stream that
could interfere with the EFV’s operation
or cause loss of service to a residence;
(3) An EFV could interfere with necessary
operation or maintenance activities,
such as blowing liquids from the line; or
(4) An EFV meeting performance requirements in § 192.381 is not commercially
available to the operator.

Move provision to Subpart H this will lead to
requiring implementation by MM; Explicitly
address EFV installation requirement on
branch service lines—clarify that EFVs are
required for service lines servicing single
family residences.
Language:
§ 192.383 Excess flow valve installation.
(a) Definitions. As used in this section:
Replaced service line means a natural gas
service line where the fitting that connects
the service line to the main line is replaced
or the piping connected to this fitting is replaced.
Service line serving single-family residence
means a natural gas service line beginning
at the fitting that connects the service line to
the main and serving only one single-family
residence.
(b) Installation required. An EFV installation
must comply with the performance standards in § 192.381. The operator must install
an EFV on new or replaced service lines
serving single-family residences after February 2, 2010, unless one or more of the
following conditions is present:
(1) The service line does not operate at a
pressure of 10 psig or greater throughout the year;
(2) The operator has prior experience
with contaminants in the gas stream
that could interfere with the EFV’s operation or cause loss of service to a residence;
(3) An EFV could interfere with necessary
operation or maintenance activities,
such as blowing liquids from the line; or
(4) An EFV meeting performance requirements in § 192.381 is not commercially
available to the operator.

§ 192.383 Excess flow valve installation.
(a) Definitions. As used in this section:
Replaced service line means a natural gas
service line where the fitting that connects
the service line to the main is replaced or
the piping connected to this fitting is replaced.
Service line serving single-family residence
means a natural gas service line that begins
at the fitting that connects the service line to
the main and serves only one single-family
residence.
(b) Installation required. An excess flow valve
(EFV) installation must comply with the performance standards in § 192.381. The operator must install an EFV on any new or replaced service line serving a single-family
residence after February 2, 2010, 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 standards in § 192.381 is not commercially
available to the operator.
(c) Reporting. Each operator must, on an
annual basis, report the number of
EFVs installed pursuant to this section
as part of the annual report required by
§ 191.11.

V. Final Rule

operators to install such valves in all
new and replaced residential service
lines serving single-family residences.
This section is revised to replace the
notification requirement with the new
requirement to install. Installation is not
required if operating pressure is less
than 10 psig, if the operator has
experience with contaminants that
would interfere with valve operation, if
an EFV is likely to interfere with
necessary operation or maintenance
activities, or if an EFV meeting the
performance standards of § 192.381 is
not commercially available. The revised
section also requires that each operator
report the number of EFVs installed
during each year in the annual report
already required (§ 192.11).
A definition for ‘‘service line serving
single-family residence’’ is added.

applicable to distribution pipeline
integrity management.

The final rule revises 49 CFR Part 192
to add integrity management
requirements applicable to distribution
pipelines. This addresses statutory
mandates and builds on previous
similar requirements established for gas
transmission pipelines. The final rule
also adds a requirement that operators
install excess flow valves (EFV) on all
new and replaced residential service
lines serving single residences, as
required by the PIPES Act.
Section-by-Section Analysis

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Section 192.383. Excess flow valve
installation
This section currently requires that
operators notify new customers of the
availability of excess flow valves (EFV)
and install a valve if the customer agrees
to pay for the installation and any
subsequent maintenance costs. This
requirement has been superseded by the
statutory mandate that PHMSA require

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Subpart P—Gas Distribution Pipeline
Integrity Management (IM)
A new subpart P is added that
includes all of the new requirements

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Section 192.1001. What definitions
apply to this subpart?
This section adds a definition for
‘‘excavation damage,’’ which is one of
the performance measures that operators
must report to PHMSA as part of their
annual reports. A common definition for
this term is needed to assure
consistency in the data collected and
thus the ability for PHMSA to analyze
the effectiveness of these regulations.
The definition is based on the definition
of damage used by the Common Ground
Alliance for its Damage Information
Reporting Tool (DIRT), a voluntary
program used by some distribution
pipeline operators to collect data on
damages to underground facilities.
A definition of the term ‘‘hazardous
leak’’ is added. The new rule will
require operators to report annually the
number of hazardous leaks repaired.
Commenters have correctly noted that a

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consistent definition will be important
to assuring that this data is useful.
Several comments suggested that
PHMSA adopt the Gas Piping
Technology Committee’s (GPTC) Guide
definition for a Grade 1 leak. This
definition is already used by many
operators to define hazardous leaks.
PHMSA has followed the suggestion of
the comments. The change to this
section adds a definition similar to that
of the GPTC Guide for Grade 1 leaks.
A definition for ‘‘integrity
management program’’ is added. An
integrity management program, as used
within this rule, is an overall approach
by an operator to ensure the integrity of
its distribution system. The program
includes an integrity management plan,
which is revised periodically. The
program also encompasses compliance
with other relevant regulations. For
some operators, the program may
involve the selection of certain materials
or adherence to professional standards
that are not mandated by Federal
regulation.
A definition for ‘‘integrity
management plan’’ is added. An
integrity management plan is a written
explanation of the mechanisms the
operator will use to implement its
integrity management program and to
ensure compliance with this rule.
A definition for ‘‘small LPG
operators’’ is added. The new rule
requires LPG operators with LPG
distribution systems serving 100 or
more customers to comply with the full
integrity management program
requirements. Small LPG operators,
those with LPG distribution systems
serving less than 100 customers from a
single source must comply with the
same requirements as master meter
operators.

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Section 192.1003. What do the
regulations in this subpart cover?
This section describes the content of
the new subpart and specifies which
operators must comply with which
sections. Master meter operators and
small LPG operators are not required to
meet all of the requirements applicable
to other operators of distribution
pipelines. The content of IM programs
required of these operators is similar
(described below), but somewhat
simpler. Documentation requirements
for these operators are different,
consistent with their treatment in the
rest of Part 192.

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Section 192.1005. What must a gas
distribution operator (other than a
master meter or small LPG operator) do
to implement this subpart?
This section requires operators of gas
distribution pipelines and of LPG
distribution pipelines serving 100 or
more customers from a single source to
develop and implement an IM program
no later than 18 months after the
effective date of this final rule. PHMSA
recognizes that IM programs are likely
to improve as operators gain experience.
This does not mean, however, that it is
acceptable for programs developed and
implemented within 18 months to be
incomplete. Those programs should
address all required elements. PHMSA
expects operators to revise their plans,
following initial implementation, to
reflect lessons that they learn through
implementing them.
Section 192.1007. What are the required
elements of an integrity management
(IM) plan?
This section defines the minimum
elements that IM plans developed by
distribution pipeline operators (other
than master meter and small LPG
operators) must address. A plan must
have written procedures for developing
and implementing the following
elements:
a. Knowledge. This section requires an
operator to develop an understanding of
its distribution pipeline. An operator
must identify the characteristics of its
pipeline’s design and operations, and of
the environment in which it operates,
which are necessary to assess applicable
threats and risks. This must include
considering information gained from
past design, operations, and
maintenance.
This section requires that operators
develop their understanding from
reasonably available information. The
rule does not require operators to
retrieve many years of archived records
or to conduct additional investigations
(e.g., excavation) to discover
information about the pipeline.
Operators have considerable knowledge
of their pipeline to support routine
operations and maintenance, but this
information may be distributed
throughout the company, in possession
of groups responsible for individual
functions. Operators must assemble this
information to the extent necessary to
support development and
implementation of their IM program.
PHMSA recognizes that there may be
gaps in the knowledge an operator has
when it develops its initial IM plan.
Operators must identify these gaps and
the additional information needed to

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improve their understanding. Operators
are required to provide a plan for
gaining that information over time
through its normal activities of
operating and maintaining their
pipeline (e.g., collecting information
about buried components when portions
of the pipeline must be excavated for
other reasons). Operators must also
develop a process by which the program
will be periodically reviewed and
refined, as needed.
b. Identify threats. Identification of
the threats that affect, or could
potentially affect, a distribution pipeline
is key to assuring its integrity.
Knowledge of applicable threats allows
operators to evaluate the risks they pose
and to rank those risks, allowing safety
resources to be applied where they will
be most effective.
This section requires that operators
consider the general categories of threats
that must now be reported on annual
reports. Reporting has been required for
many years, meaning that data are
available regarding these threat
categories. Operators are required to
consider reasonably available
information to identify threats that
affect their pipeline or that could
potentially affect it (e.g., landslides in a
hilly area with loose soils even if no
landslide has been experienced). The
section specifies data sources resulting
from normal operation and maintenance
that operators may consider in
evaluating threats.
c. Evaluate and rank risk. This section
requires that an operator evaluate the
identified threats to determine their
relative importance and rank the risks
associated with its pipeline. Operators
must consider the likelihood of threats
as well as the consequences of a failure
that might result from each threat.
Consideration of consequences is
important to assure that risks are
properly ranked. A potential accident of
relatively low likelihood but that would
produce significant consequences may
be a higher risk than an accident with
somewhat greater likelihood but that
cannot produce major consequences.
Operators may subdivide their
pipeline into regions for purposes of
this analysis. Such division may be
appropriate when factors relevant to a
threat vary within the pipeline. For
example, the threat of corrosion is not
applicable to portions of the pipeline
made of plastic materials. The corrosion
threat likely would be of different
importance to metal portions of the
pipeline that are coated and
cathodically protected than it would be
to any portions that are bare or
unprotected. Operators are not,
however, required to divide their

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pipelines for purposes of analyzing
risks.
d. Identify and implement measures
to address risks. Operator IM programs
must include measures designed to
reduce the risk of failure from identified
threats. These measures must include an
effective leak management program
(which most operators are already
implementing) unless the operator
already repairs all leaks when found.
e. Measure performance, monitor
results, and evaluate effectiveness.
Measuring performance is a key element
of IM programs. This section requires
operators to develop performance
measures, including some that are
specified for use by all operators.
Measuring performance periodically
allows operators to determine whether
actions being taken to address threats
are effective, or whether different or
additional actions are needed.
f. Periodic Evaluation and
Improvement. This element requires
operators to periodically re-evaluate
risks on their entire pipeline and to
consider the relevance of threats in one
location to other locations. Operators
must consider the results of their
performance monitoring in these
evaluations, which must be performed
at least once every five years. An
operator must determine an appropriate
period for conducting a complete
program evaluation based on the
complexity of its system. An operator
should conduct a program evaluation
any time there are changes in factors
that would affect the risk of failure.
g. Report results. This section requires
that operators include in their annual
reports some of the performance
measures required by the rule. PHMSA
will use this data to evaluate the overall
effectiveness of distribution IM
requirements. (Note that one of the
measures required to be reported—all
leaks repaired, by cause—has
historically been required on the annual
report).
Section 192.1009. What must an
operator report when compression
couplings fail?
Compression couplings are
mechanical fittings used to connect
sections of pipe. Such couplings are
often used to connect plastic pipe to
metal pipe. Failure of compression
couplings has resulted in a number of
serious accidents on distribution
pipelines. This section requires that
operators report information related to
failure of compression couplings
(excluding failures that result only in
non-hazardous leaks) on their annual
report. PHMSA will use this data to
evaluate the scope of problems related

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to compression couplings and will
determine if changes to the regulations
are appropriate to help prevent
incidents caused by coupling failure.
Section 192.1011. What records must an
operator keep?
This section requires that operators
keep records for 10 years that
demonstrate compliance with the
requirements of this new subpart. The
records must include superseded copies
of IM plans.
Section 192.1013. When may an
operator deviate from required periodic
inspections under this part?
The operator’s evaluation of threats
and risk may identify additional actions
that could be effective in reducing risk
on distribution pipelines. This section
allows operators to reduce the frequency
of actions now required by this Part to
be conducted periodically, to realign
safety resources to better address risks.
Operators must receive approval from
their safety regulator (PHMSA or state,
as appropriate) before they can reduce
the required frequency, and must
demonstrate that the overall effect of
their proposed change will be an equal
or greater level of pipeline safety.
This section requires an operator to
submit a proposal that explains the
desired alternative frequency for a
required periodic inspection and that
explains other actions the operator will
take as part of the integrity management
program to ensure an equal or greater
overall level of pipeline safety. A
proposal should include sufficient
information to explain how the IM plan
and IM program would be modified if
the proposal is approved. States will use
their authority to approve reductions in
the frequency of safety actions
otherwise required by Part 192.
Section 192.1015. What must a master
meter or small liquefied petroleum gas
(LPG) operator do to implement this
subpart?
Most master meter operators are small
entities and operating their gas
distribution pipelines is not their
principal occupation. These operators
typically have limited on-staff technical
pipeline expertise. These operators have
historically been treated differently
within Part 192. In particular, they have
been subject to more limited
documentation requirements. For
example, master meter operators and
operators of LPG distribution pipelines
that serve fewer than 100 customers
from a single source are not required to
submit annual reports.
This section prescribes IM
requirements applicable to these smaller

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63931

operators. The major elements that these
operators are required to include in
their IM plans are the same as those in
§ 192.1007 applicable to other operators.
The details of the elements are
simplified somewhat, to reflect both the
relative simplicity of these pipelines
and the limited capability of the
operators. For example, the required
knowledge of their pipeline is focused
on the approximate location and
material of which it is constructed and
required documentation of this
knowledge is limited to documents
showing the location and material of
piping and appurtenances that are
installed after the effective date of their
IM programs and, to the extent known,
in existence when the program becomes
effective. These operators are not
required to submit performance
measures, which is consistent with their
prior treatment with respect to annual
reports.
PHMSA expects that the IM plans
developed by these operators will be
simpler than those developed by
operators of more complex distribution
pipelines. PHMSA is developing
guidance suitable for use by master
meter and small LPG operators to
develop simple IM plans for their
pipelines. This guidance will be made
available via PHMSA’s web site after
this final rule is published.
VI. Regulatory Analyses and Notices
A. Statutory/Legal Authority for This
Rulemaking
This final rule 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
integrity management program
regulations are issued under this
authority and address NTSB and DOT
Inspector General 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. No.
109–468, Dec. 29, 2006, codified at 49
U.S.C. § 60109(e)).
B. Executive Order 12866 and DOT
Regulatory Policies and Procedures
Executive Order 12866 directs all
Federal agencies to consider the costs
and benefits of ‘‘significant regulatory
actions.’’ Federal agencies are directed

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to develop a formal Regulatory Impact
Analysis consistent with OMB Circular
A–4 for all ‘‘economically significant’’
rules, or those rules estimated to have
an impact of $100 million or more in
any one year.
DOT considers this an ‘‘economically
significant’’ regulatory action under
section 3(f)(1) of Executive Order 12866
(58 FR 51735; October 4, 1993). This
final rule is also significant under DOT’s
regulatory policies and procedures (44
FR 11034; February 26, 1979). PHMSA
prepared a Regulatory Evaluation for
this final rule and placed it in the public
docket.
The rule’s requirements would affect
an estimated 9,343 natural gas operators
with a combined total of 1,138,000
miles of mains and 60,970,000 services.
Of these operators, 201 are large local
gas utilities, 1,090 are small local gas
utilities, 52 are LPG operators servicing
100 or more customers from a single
source, and approximately 8,000 are
master meter and small LPG systems.
PHMSA determined that the
approximately 1,142 gas operators and
the 8,000 master meter operators and
LPG systems are small.
The monetized benefits resulting from
the final rule are estimated to be
between $165 million and $170 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
• The end of the existing EFV
notification requirement
The costs of the final rule are
estimated to be $130 million in the first
year and $101 million in each
subsequent year. Those costs cover:
• Development of an IM program
• Implementation of the IM program
(data acquisition and analysis)
• Mitigation of risks (leak
management, excess flow valve
installation and other)
• Reporting to PHMSA and State
Regulators
• Recordkeeping
• Management of the IM program.
The Regulatory Impact Analyses (RIA)
finds that the rule is not expected to
adversely affect the economy or the
environment. The analysis finds that,
for those costs and benefits that can be
quantified, the present value of net
benefits is expected to be between $21

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million and $1.6 billion over a 50-year
period after all of the requirements are
implemented. Furthermore, the rule is
expected yield positive net benefits if it
results in eliminating only
approximately 12.2 percent of the
societal costs the first year, and about
9.5 percent in subsequent years.
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 IM
program requirements in this rule apply
to gas distribution pipeline operators
and require operators of gas distribution
pipelines to develop and implement IM
plans 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 rule will affect
approximately 9,090 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 1,090 small operators among the
local gas distribution utilities with
12,000 or fewer services and
approximately 8,000 master meter and
LPG systems, all of which are small.
Furthermore, PHMSA estimates the
rule will cost each of the 1,090 small
operators and the 52 LPG operators
serving 100 or more customers from a
single source, on average, approximately
$33,600 in the first year and $15,400 in
each subsequent year. PHMSA also
estimates that the rule will cost each of
the 8,000 master meter and small LPG
systems, on average, approximately
$2,900 in the first year and $1,100 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 rule may
be significant for at least some of the
small entities, if the costs exceed 1
percent of the revenues. Therefore,
PHMSA believes that the rule could
result in a significant adverse economic
impact for some of the smallest affected
entities.
PHMSA has minimized costs for these
small operators. As mentioned earlier,
small operators’ IM programs will be
subject to more limited documentation
requirements. PHMSA is also providing
guidance for small operators.

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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.
This rule requires operators to report
four distribution integrity management
program (DIMP) performance measures
in the annual report (Incident and
Annual Reports for Gas Pipeline
Operators. OMB Control Number: 2137–
0522). All data required under this rule
to be reported will be reported via the
annual report.
One of the measures required to be
reported—all leaks repaired, by cause—
has historically been required as part of
annual reports. The other information to
be reported will require modifications to
the annual report form. Therefore,
PHMSA is also using this rulemaking as
a 60-day notice to revise the annual
report information collection, OMB
Control Number 2137–0522. PHMSA
seeks comment on the proposed
modified annual report form, which is
available in the docket for this
rulemaking.
In addition, the rule also requires
operators to report, as part of the annual
report, detailed information regarding
compression coupling failures. PHMSA
has created a compression coupling
failure addendum to be submitted with
the annual report form, as needed.
PHMSA also seeks comment on the
proposed compression coupling failure
addendum form. This form will also be
part of the revised 2137–0522
information collection and is available
in the docket for this rulemaking.

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PHMSA estimates that the additional
average time required for completing the
annual report, beyond the time that gas
distribution operators are already
expending, is 6 hours per year per
operator. This results in a burden
increase of 8,058 hours per year for all
1,343 operators that have to comply
with the annual report requirements.
The required information can be
reported electronically. Operators are
permitted to keep records in any
retrievable form. They may use the
latest information technology to reduce
the additional information-collection
burden.
In addition to the reporting
requirements, this final rule requires
each affected operator to develop and
maintain a written integrity
management plan, which includes
initial plan development, recordkeeping
and updates. These non-reporting
requirements are covered by Integrity
Management Program for Gas
Distribution Pipelines, OMB Control
Number: 2137–0625. OMB assigned
Control Number 2137–0625 to the
information collection but withheld
approval pending publication of this
Final Rule, which addresses comments
to the Notice. This Final Rule serves as
a 30-day notice for the information
collection, and PHMSA will forward an
information collection package for OMB
review concurrent with publication of
this final rule.
Each operator, other than master
meter operators and small LPG
operators, must also collect and record
one other specified performance
measure and any other performance
measures unique to the operator’s
pipeline that are needed to evaluate the
effectiveness of the integrity
management program. PHMSA
estimates these tasks will require an
additional 2,289 hours for all 9,343
operators. An explanation of all burden
hour estimates is contained in the
Paperwork Reduction Act Supporting
Statement and the Regulatory Impact
Analysis (RIA) available in the docket
for this rulemaking.

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E. Executive Order 13084
This final rule has been analyzed
under principles and criteria contained
in Executive Order 13084
(‘‘Consultation and Coordination with
Indian Tribal Governments’’). Because
this rule 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.

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F. Executive Order 13132

G. Executive Order 13211

PHMSA analyzed this final rule 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 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 that required by this rule.
Under 49 U.S.C. 60107, PHMSA
provides grant money to participating
states 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 requirements. We expect
to increase money available to help
states.
PHMSA has concluded this rule does
not include 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 rule preempts any currently
established state requirements in this
area. States have the ability to augment
pipeline safety requirements for
pipelines, but are not able to approve
safety requirements less stringent than
those contained within this rule.
Although the consultation
requirements do not apply, the states
have played an integral role in helping
develop these requirements. State
pipeline safety regulatory agencies
participated in the stakeholder groups
that helped develop the findings on
which this rule is based and provided
guidance through NARUC in the form of
a resolution. PHMSA action is
consistent with this resolution.

This final rule 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 rule as a significant energy action.

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H. Unfunded Mandates
PHMSA estimates that this final rule
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 $141.3
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 our rule’s objectives.
I. National Environmental Policy Act
PHMSA analyzed this final rule 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 determined that this
action will not significantly affect the
quality of the human environment.
PHMSA conducted an Environmental
Assessment on the NPRM and did not
receive any comment on the preliminary
analysis. The Environmental
Assessment is available for review 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 is amending 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, 60116, 60118,
and 60137; and 49 CFR 1.53.

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2. Section 192.383 is revised to read
as follows:

Subpart P—Gas Distribution Pipeline
Integrity Management (IM)

§ 192.383

§ 192.1001
subpart?

■

Excess flow valve installation.

(a) Definitions. As used in this
section:
Replaced service line means a natural
gas service line where the fitting that
connects the service line to the main is
replaced or the piping connected to this
fitting is replaced.
Service line serving single-family
residence means a natural gas service
line that begins at the fitting that
connects the service line to the main
and serves only one single-family
residence.
(b) Installation required. An excess
flow valve (EFV) installation must
comply with the performance standards
in § 192.381. The operator must install
an EFV on any new or replaced service
line serving a single-family residence
after February 2, 2010, 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
standards in § 192.381 is not
commercially available to the operator.
(c) Reporting. Each operator must, on
an annual basis, report the number of
EFVs installed pursuant to this section
as part of the annual report required by
§ 191.11.
■ 3. In Part 192, a new subpart P is
added to read as follows:

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■

Subpart P—Gas Distribution Pipeline
Integrity Management (IM)
Sec.
192.1001 What definitions apply to this
subpart?
192.1003 What do the regulations in this
subpart cover?
192.1005 What must a gas distribution
operator (other than a master meter or
small LPG operator) do to implement
this subpart?
192.1007 What are the required elements of
an integrity management plan?
192.1009 What must an operator report
when compression couplings fail?
192.1011 What records must an operator
keep?
192.1013 When may an operator deviate
from required periodic inspections of
this part?
192.1015 What must a master meter or
small liquefied petroleum gas (LPG)
operator do to implement this subpart?

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What definitions apply to this

The following definitions apply to
this subpart:
Excavation Damage means any
impact that results in the need to repair
or replace an underground facility due
to a weakening, or the partial or
complete destruction, of the facility,
including, but not limited to, the
protective coating, lateral support,
cathodic protection or the housing for
the line device or facility.
Hazardous Leak means a leak that
represents an existing or probable
hazard to persons or property and
requires immediate repair or continuous
action until the conditions are no longer
hazardous.
Integrity Management Plan or IM Plan
means a written explanation of the
mechanisms or procedures the operator
will use to implement its integrity
management program and to ensure
compliance with this subpart.
Integrity Management Program or IM
Program means an overall approach by
an operator to ensure the integrity of its
gas distribution system.
Small LPG Operator means an
operator of a liquefied petroleum gas
(LPG) distribution pipeline that serves
fewer than 100 customers from a single
source.
§ 192.1003 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,
including liquefied petroleum gas
systems. A gas distribution operator,
other than a master meter operator or a
small LPG operator, must follow the
requirements in §§ 192.1005–192.1013
of this subpart. A master meter operator
or small LPG operator of a gas
distribution pipeline must follow the
requirements in § 192.1015 of this
subpart.
§ 192.1005 What must a gas distribution
operator (other than a master meter or
small LPG operator) do to implement this
subpart?

No later than August 2, 2011 a gas
distribution operator must develop and
implement an integrity management
program that includes a written integrity
management plan as specified in
§ 192.1007.
§ 192.1007 What are the required elements
of an integrity management plan?

A written integrity management plan
must contain procedures for developing

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and implementing the following
elements:
(a) Knowledge. An operator must
demonstrate an understanding of its gas
distribution system developed from
reasonably available information.
(1) Identify the characteristics of the
pipeline’s design and operations and the
environmental factors that are necessary
to assess the applicable threats and risks
to its gas distribution pipeline.
(2) Consider the information gained
from past design, operations, and
maintenance.
(3) Identify additional information
needed and provide a plan for gaining
that information over time through
normal activities conducted on the
pipeline (for example, design,
construction, operations or maintenance
activities).
(4) Develop and implement a process
by which the IM program will be
reviewed periodically and refined and
improved as needed.
(5) Provide for the capture and
retention of data on any new pipeline
installed. The data must include, at a
minimum, the location where the new
pipeline is installed and the material of
which it is 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, weld or joint failure (including
compression coupling), equipment
failure, incorrect operation, and other
concerns that could threaten the
integrity of its pipeline. An operator
must consider reasonably available
information to identify existing and
potential threats. Sources of data may
include, but are not limited to, incident
and leak history, corrosion control
records, continuing surveillance
records, patrolling records, maintenance
history, and excavation damage
experience.
(c) Evaluate and rank risk. An
operator must evaluate the risks
associated with its distribution pipeline.
In this evaluation, the operator must
determine the relative importance of
each threat and estimate and rank the
risks posed to its pipeline. 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 its pipeline into
regions with similar characteristics (e.g.,
contiguous areas within a distribution
pipeline consisting of mains, services
and other appurtenances; areas with
common materials or environmental
factors), and for which similar actions

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Federal Register / Vol. 74, No. 232 / Friday, December 4, 2009 / Rules and Regulations
likely 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. These measures
must include an effective leak
management program (unless all leaks
are repaired when found).
(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 as required by
§ 192.703(c) of this subchapter (or total
number of leaks if all leaks are repaired
when found), 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) Total number of leaks either
eliminated or repaired, categorized by
cause;
(v) Number of hazardous leaks either
eliminated or repaired as required by
§ 192.703(c) (or total number of leaks if
all leaks are repaired when found),
categorized by material; and
(vi) Any additional measures the
operator determines are needed to
evaluate the effectiveness of the
operator’s IM program in controlling
each identified threat.
(f) Periodic Evaluation and
Improvement. An operator must reevaluate threats and risks on its entire
pipeline and consider the relevance of
threats in one location to other areas.
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, on an
annual basis, the four measures listed in
paragraphs (e)(1)(i) through (e)(1)(iv) of
this section, as part of the annual report
required by § 191.11. An operator also
must report the four measures to the
state pipeline safety authority if a state
exercises jurisdiction over the operator’s
pipeline.

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§ 192.1009 What must an operator report
when compression couplings fail?

Each operator must report, on an
annual basis, information related to
failure of compression couplings,
excluding those that result only in nonhazardous leaks, as part of the annual
report required by § 191.11 beginning
with the report submitted March 15,
2011. 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, coupling manufacturer,
lot number and date of manufacture,
and other information that can be found
in markings on the failed coupling. An
operator also must report this
information to the state pipeline safety
authority if a state exercises jurisdiction
over the operator’s pipeline.
§ 192.1011
keep?

What records must an operator

An operator must maintain records
demonstrating compliance with the
requirements of this subpart for at least
10 years. The records must include
copies of superseded integrity
management plans developed under this
subpart.
§ 192.1013 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.
(b) An operator must submit its
proposal to the PHMSA Associate
Administrator for Pipeline Safety or, in
the case of an intrastate pipeline facility
regulated by the State, the appropriate
State agency. The applicable oversight
agency may accept the proposal on its
own authority, with or without
conditions and limitations, on a
showing that the operator’s proposal,
which includes the adjusted interval,
will provide an equal or greater overall
level of safety.
(c) An operator may implement an
approved reduction in the frequency of
a periodic inspection or test only where
the operator has developed and
implemented an integrity management
program that provides an equal or
improved overall level of safety despite
the reduced frequency of periodic
inspections.
§ 192.1015 What must a master meter or
small liquefied petroleum gas (LPG)
operator do to implement this subpart?

(a) General. No later than August 2,
2011 the operator of a master meter
system or a small LPG operator must

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63935

develop and implement an IM program
that includes a written IM plan as
specified in paragraph (b) of this
section. The IM program for these
pipelines should reflect the relative
simplicity of these types of pipelines.
(b) Elements. A written integrity
management plan must address, at a
minimum, the following elements:
(1) Knowledge. The operator must
demonstrate knowledge of its pipeline,
which, to the extent known, should
include the approximate location and
material of its pipeline. The operator
must identify additional information
needed and provide a plan for gaining
knowledge over time through normal
activities conducted on the pipeline (for
example, design, construction,
operations or maintenance 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 failure, and incorrect
operation.
(3) Rank risks. The operator must
evaluate the risks to its pipeline and
estimate the relative importance of each
identified threat.
(4) Identify and implement measures
to mitigate risks. The operator must
determine and implement measures
designed to reduce the risks from failure
of its pipeline.
(5) Measure performance, monitor
results, and evaluate effectiveness. The
operator must monitor, as a performance
measure, the number of leaks eliminated
or repaired on its pipeline and their
causes.
(6) Periodic evaluation and
improvement. The operator must
determine the appropriate period for
conducting IM program evaluations
based on the complexity of its pipeline
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.
(c) Records. The operator must
maintain, for a period of at least 10
years, the following records:
(1) A written IM plan in accordance
with this section, including superseded
IM plans;
(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

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appurtenances that were existing on the
effective date of the operator’s program.

Issued in Washington, DC on November 20,
2009 under Authority delegated in Part 1.
Cynthia L. Quarterman,
Administrator.
[FR Doc. E9–28467 Filed 12–3–09; 8:45 am]

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BILLING CODE 4910–60–P

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