[Federal Register: December 4, 2009 (Volume 74, Number 232)]
[Rules and Regulations]
[Page 63905-63936]
[DOCID:fr04de09-29]

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Part III

Department of Transportation

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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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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

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

ACTION: Final rule.

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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 risk-based adjustment of prescribed intervals for leak detection
surveys and other fixed-interval requirements in the agency's existing
regulations for gas distribution pipelines. To further minimize
regulatory burdens, the 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.

ADDRESSES: Comments limited to the provisions on reporting failures of
mechanical couplings should reference Docket No. PHMSA-RSPA-2004-19854
and may be submitted in the following ways:
     E-Gov Web site: http://www.regulations.gov. This site
allows the public to enter comments on any Federal Register notice
issued by any agency.
     Fax: 1-202-493-2251.
     Mail: DOT Docket Operations Facility (M-30), U.S.
Department of Transportation, West Building, 1200 New Jersey Avenue,
SE., Washington, DC 20590.
     Hand Delivery: DOT Docket Operations Facility, U.S.
Department of Transportation, West Building, Room W12-140, 1200 New
Jersey Avenue, SE., Washington, DC 20590 between 9 a.m. and 5 p.m.,
Monday through Friday, except Federal holidays.
    Instructions: In the E-Gov Web site: http://www.regulations.gov,
under ``Search Documents'' select ``Pipeline and Hazardous Materials
Safety Administration.'' Next, select ``Notices,'' and then click
``Submit.'' Select this rulemaking by clicking on the docket number
listed above. Submit your comment by clicking the yellow bubble in the
right column then following the instructions.
    Identify docket number PHMSA-RSPA-2004-19854 at the beginning of
your comments. For comments by mail, please provide two copies. To
receive PHMSA's confirmation receipt, include a self-addressed stamped
postcard. Internet users may access all comments at http://
www.regulations.gov, by following the steps above.

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

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

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.

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 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 cost-beneficial. 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
pipeline-specific 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 (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

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 Sec.
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 adequately
collecting and analyzing this 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 60-day 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 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

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.
    At the same time, PHMSA is sympathetic to the need to have well-
defined 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 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 1\1/2\ 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

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\
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    \1\ Pipeline Safety Improvement Act of 2002, Section 14.
    \2\ 49 Code of Federal Regulations, Section 192.907.
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    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 Sec.  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 Government-wide requirement to
write regulations in ``plain English.'' PHMSA has been consistently
using this format in its pipeline rulemakings for some time. PHMSA has
revised Sec.  192.1005(b) to delete the reference to ``processes.''
    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 cost-beneficial 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 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

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 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 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.
---------------------------------------------------------------------------

    \3\ 49 United States Code, Section 60118.
---------------------------------------------------------------------------

    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

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 risk-based
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 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, 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

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.
---------------------------------------------------------------------------

    \4\ Operators of LPG systems serving more than 100 customers are
required to file annual reports.
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

    \5\ 49 Code of Federal Regulations, section 191.5.
---------------------------------------------------------------------------

    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 Sec.  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 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

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.
---------------------------------------------------------------------------

    \6\ 49 United States Code, section 60109(e)(1).
---------------------------------------------------------------------------

    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
Sec.  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 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.
---------------------------------------------------------------------------

    \7\ See Sec.  192.941, What is a low stress reassessment?
    \8\ PHMSA, ``Integrity Management for Gas Distribution: Report
of Phase 1 Investigations,'' December 2005, page 23.
---------------------------------------------------------------------------

    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 Sec.  192.1007(d)) because the requirement is open-
ended. They suggested that Sec.  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 Sec.  192.723 and damage prevention requirements in Sec.
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 high-level 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 Sec.  192.723.
    Operators are required to implement a damage prevention program
under Sec.  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 state-run. PHMSA is persuaded that modifications
to damage prevention requirements for distribution systems should be
made through amendments to Sec.  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 Sec.
192.614

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, noting
that excessive documentation does not support safety. NAPSR would limit
the requirement for procedures in proposed Sec.  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 Sec.
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 Sec.  192.1015; Final Rule Sec.  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 Sec.  192.1007. PHMSA believes this is the type of
information to which Florida was referring in its comment.
    PHMSA has revised Sec.  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.

    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 Sec.  192.383. PHMSA has included in
revised Sec.  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 PHMSA's intent.
    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 Sec.  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 Sec.  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 Sec.  192.383(a) be moved to Sec.
192.381, since it would be lost with repeal of Sec.  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 Sec.  192.383, is to require an operator to notify a
customer of the availability of an EFV if replacement work provides an
opportunity to install an EFV, even if this involves less than
replacement of 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 Sec.  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 re-evaluated 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

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 Sec.  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 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 Sec.
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 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.

    APGA, Iowa, and a number of operators objected to the proposed
requirement in Sec.  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 re-evaluation 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, re-evaluations 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 operators, these types of changes may 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 Sec.  192.1005(b) (as well as
the requirement to continually refine and improve in proposed Sec.
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 Sec.  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 Sec.
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 Sec.  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 Sec.  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)).
    f. Consideration of threats in re-evaluation.
    Another operator suggested that PHMSA delete the requirement in
proposed Sec.  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 Sec.  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 Sec.  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

performance. We plan to address this issue outside this rulemaking.
    Comment Topic 18: Continuing surveillance.
    Iowa and a large operator suggested that we revise Sec.  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 Sec.  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 (Sec.  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 sub-paragraph (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 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 Sec.  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 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 (Sec.
192.1007(a)(2)). They would revise proposed Sec.  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.

    An operator would change ``piping system'' and ``piping and
appurtenances'' in paragraph (a)(5) to ``pipeline'' for consistency
with the definition of pipeline in Sec.  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 Sec.  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 Sec.
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 Sec.  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.
    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 Sec.  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.
    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 non-
mathematical 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.

    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 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-the-art 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.
---------------------------------------------------------------------------

    \9\ PHMSA, ``Integrity Management for Gas Distribution: Report
of Phase 1 Investigations,'' December 2005, page 16.
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

    \10\ 49 Code of Federal Regulations, Section 192.614(b).
---------------------------------------------------------------------------

    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

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 mean that these
measures are not ``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-
by-material 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 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 Sec.  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 performance-
based 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.