We received a number of comments concerning the regulatory analysis

supporting the proposed rule: In response to a question about whether
the proposed performance measures were burdensome, two commenters
stated they were not. Other commenters raised specific issues regarding
the regulatory analysis.
    a. Assumptions used in the analysis.
    NAPSR, AGA, an operator association, and an individual operator
commented that assumptions made in the analysis are not supported. In
particular, the assumption that implementing the proposed rule will
result in a 50 percent reduction in incidents, which is key to the
analysis of the benefits of the proposal, appears to have no
foundation.
    PHMSA response: It is not possible to determine precisely the
effectiveness of a new regulation before it is implemented. It is
therefore necessary to make assumptions for purposes of analysis. The
analysis then includes an evaluation of the sensitivity of its
conclusions to those assumptions. Here, PHMSA expects that the
regulation will help ensure the integrity of distribution pipelines and
will reduce the number and severity of incidents that occur on these
pipelines. An assumption of a 20 percent to 50 percent reduction in
incidents was made for purposes of analysis, but that assumption is not
critical to the conclusions. The final regulatory impact analysis
demonstrates,\11\ in fact, that societal costs associated with gas
distribution need only be reduced by about 12.2 percent in the first
year and 9.5 percent in successive years for the rule to yield positive
net benefits.
---------------------------------------------------------------------------

    \11\ Final Regulatory Impact Analysis, ``Summary and
Conclusions'', p. 61.
---------------------------------------------------------------------------

    b. Lost gas.
    AGA and an operator noted that assumptions concerning lost gas are
not supported. They refer to the stakeholder report where the
difficulties of measuring lost gas are discussed. That report states
that reported ``lost gas'' often reflects measurement uncertainties
rather than actual losses.
    PHMSA response: Whether the amount of lost gas can be measured with
accuracy does not affect whether gas is actually lost. PHMSA
understands that the amount of lost gas reported may depend as much on
measurement uncertainties as on actual losses, but concludes that
actual loss does occur. This rule will have the effect of improving
leak management, and damage prevention. The requirement that excess
flow valves be installed will reduce the amount of gas released if a
service line is damaged by excavation. All of these actions will reduce
the amount of gas lost. PHMSA has relied on information from the EPA
for its assumptions concerning lost gas, and considers that the
estimated reduction of 10 percent cited in the regulatory impact
analysis is reasonable.
    c. Competitive market.
    AGA, an operator association, and an operator disagreed with our
conclusion that local gas distribution is not a competitive market.
They noted that utility commissions consider all market forces and that
some States have deregulated this function.
    PHMSA response: PHMSA recognizes that utility regulatory
commissions consider market forces in their rate regulating activities
and that some aspects of natural gas supply have been deregulated in
some States. Nevertheless, distribution of natural gas has not been
completely deregulated in any areas of which PHMSA is aware--i.e., a
customer does not have a choice of multiple suppliers for natural gas
delivered to its residence or place of business. Thus, PHMSA considers
that the statement made was accurate. It did not affect the conclusions
of the analysis.
    d. Cost effective.
    FL PSC suggested that the proposal is not cost effective, noted
that recent regulatory extensions have been extensive, and suggested we
review the current regulations, in total, before proposing more. They
pointed to a rate case in which a company is requesting $750,000 to
implement distribution IM for a system containing 10,000 miles of
distribution mains, and that applying the unit rate to the total
mileage of distribution mains in the U.S. would result in an estimated
implementation cost of nearly $84 million. This would equate to more
than $3.8 million per death averted if all deaths resulting from
accidents on distribution systems could be eliminated, which they
contend is not a practical assumption. FL PSC also commented that State
regulators are overburdened and cannot do more than they are now.
    PHMSA response: It is unclear what basis an operator would have
used for a rate case addressing implementation of distribution IM at
the time of the NPRM, since requirements for that purpose were not
final. This final rule makes significant changes from the NPRM, most of
which will have the effect of reducing costs. PHMSA has analyzed the
costs and benefits that are expected to result from this final rule and
has concluded that the rule is cost-beneficial.
    PHMSA recognizes that State regulatory programs will be required to
undertake new work as a result of this rule. PHMSA supports State
pipeline safety programs through grants and is increasing the level of
that support. States exercise regulatory authority over intrastate
pipelines once they are certified by PHMSA to do so.
    e. Burden hour estimate.
    A consultant noted that the estimate in the regulatory analysis of
[frac14] hour for master meter operators to update their programs is
unrealistic. He believes that 4 hours is a better estimate for such an
update.
    PHMSA response: The regulatory analysis and the paperwork reduction
act burdens have been recalculated based on comments to the NPRM. PHMSA
has revised the estimate to twelve hours per year for master meter
operators to update their programs.
    Comment Topic 25: IM for new pipelines.
    The Missouri Public Service Commission noted that the proposed rule
provides many requirements to address the integrity of existing
distribution pipeline systems but is silent on the need to assure
integrity for new installations. Missouri suggested the rule address
how well a pipeline system is built/constructed/installed, which is
critical to its integrity. Missouri also suggested adding increased
inspection requirements for contractors performing new installations to
assure the integrity of new pipelines being installed, and to not
install pipelines today that will create integrity issues in the
future.
    PHMSA response: PHMSA agrees that good installation/construction is
important to assuring pipeline integrity. This proposal, however, deals
with assuring the integrity of existing pipeline systems. Construction
is addressed by other regulations for which changes were not proposed
as part of this rulemaking. PHMSA may consider changes to construction
regulations as part of future rulemaking activities.
    Comment Topic 26: Annual report form.
    One operator suggested that PHMSA should develop its reporting
forms by working in conjunction with AGA and APGA.
    PHMSA response: All data required to be reported will be reported
via the annual report. PHMSA has revised the annual report form using
its normal procedure, which included consultation with the trade
associations.
    This final rule requires operators to report four integrity
management performance measures as part of the annual report. The rule
also requires operators to report, as part of the annual report,
detailed information regarding

compression coupling failures. One of the performance measures--total
number of leaks eliminated or repaired, categorized by cause--is
already a part of the annual report form; however, the other
information to be reported will require modifications to the annual
report form. Therefore, PHMSA is issuing, in conjunction with this
rulemaking, a 60-day notice to modify the annual report information
collection, OMB Control Number 2137-0522. PHMSA seeks comment on the
proposed modified annual report form.

III. National Transportation Safety Board

    The National Transportation Safety Board (NTSB) is an independent
agency that investigates major transportation accidents, including
those occurring on pipelines. The NTSB makes recommendations to PHMSA
when it concludes from investigation of pipeline accidents that
additional regulatory actions would be appropriate to improve safety.
    The NTSB submitted comments on this rulemaking on November 19,
2008. The NTSB supported the approach to distribution IM being taken by
PHMSA and stated that ``overall, the NPRM provides a reasonable and
logical approach that operators of distribution pipelines can use to
develop and implement integrity management plans.'' The NTSB also
identified three areas in which they concluded the proposed rule should
be improved.
    The NTSB considers that an effective leak management program, as
required in this rule, must provide for use of equipment that prevents
or mitigates leaks. The Board sees EFVs as equipment that should be
used for this purpose. The NTSB acknowledges that the proposed rule's
requirements for installation of EFVs implement the mandate in the
PIPES Act of 2006, but considers that it should go farther. The NTSB
recommends that the rule require the installation of EFVs on all new
and replaced customer service lines, regardless of customer
classification. This would include multi-family dwellings (e.g.,
apartment buildings) and commercial properties. This is consistent with
a recommendation the NTSB made in 2001 following investigation of a
pipeline accident.
    We have considered requirements for installation of EFVs for many
years. PHMSA has conducted two cost-benefit studies. These studies
reached contrary conclusions on whether a requirement to install EFVs
was cost beneficial and demonstrated that the conclusion on whether EFV
installation is cost-beneficial is highly sensitive to the assumptions
and data used in the analysis. The PIPES Act required that PHMSA
include in this final rule a requirement to install EFVs on new and
replaced service lines serving single-family residences. This addresses
the vast majority of gas distribution service lines, and this
requirement has been included in this final rule. PHMSA has not studied
separately the required installation of EFVs on properties other than
single-family residences and is uncertain whether such a requirement
can be justified on a cost-benefit basis.
    The arguments for installing EFVs are that they are effective in
preventing accidents caused by significant damage to a downstream
service line and that they are inexpensive to install (when the line is
newly installed or excavated for other reasons). The contrary argument
is that an EFV protects only the service line in which it is installed
and incidents causing significant damage to a service line are rare.
Thus, a large number of EFVs must be installed, at a large cumulative
expense, before one can say with confidence that it is likely that the
presence of the installed valves will prevent an accident.
    The potential consequences of accidents involving service line
damage at multi-family or commercial properties are likely larger than
those that would result from accidents on a service line serving a
single-family residence. The likelihood that an individual service line
would be damaged remains, however, small, and the likelihood that an
EFV would prevent an accident at an individual installation is
correspondingly small. There are far fewer multi-family and commercial
properties than there are single-family residences. This could reduce
the likelihood that an EFV would be expected to prevent an accident at
such a property so that a cost-benefit analysis would conclude that
requiring installation of the valves is not justified. Before imposing
such a requirement, PHMSA would need to collect data from manufacturers
of larger EFVs and from operators who currently install such valves and
conduct a detailed cost-benefit analysis. These actions have not been
completed, and PHMSA has not expanded the requirement in this final
rule beyond the mandate in the PIPES Act.
    The NTSB also recommended that the final rule be revised to address
more explicitly the risks from compression couplings. The Board noted
that it has investigated a number of accidents caused by pipe pulling
out of compression couplings, and that several states have taken
actions to require replacement or other actions to assure that
compression coupling joints are safe. The NTSB recommended that the
rule include specific guidance on how to identify and address problem
compression couplings.
    PHMSA agrees that there are reasons for concern regarding
compression couplings. PHMSA issued an advisory bulletin on this
subject on February 28, 2008. The NTSB acknowledged that this bulletin
should help utilities identify future problems, but expressed concern
that it is only advisory and that operators are not required to
implement its suggestions.
    PHMSA will encourage GPTC to review its guidance with respect to
compression couplings and to improve that guidance, if needed. PHMSA
has revised this final rule to require that operators report
information on coupling failures as part of their annual report to
PHMSA (see comment topic 1 above). PHMSA will consider the data from
these reports to decide whether additional requirements relative to
compression couplings are warranted. Any additional requirements
related to compression couplings would be outside the scope of the
proposed rule.
    Finally, the NTSB recommended that the rule include specific
requirements that operators address risks from directional drilling.
PHMSA has not made this change for the same reasons as described above
for compression couplings. Directional drilling is a type of excavation
damage, a threat category operators are required to consider. We expect
that GPTC will provide guidance on considering the threat of
directional drilling.

IV. Advisory Committee

    On December 12, 2008, PHMSA discussed the proposed rule with the
Technical Pipeline Safety Standards Committee (TPSSC). The TPSSC is a
statutorily mandated advisory committee that advises PHMSA about the
technical feasibility, reasonableness and cost-effectiveness of its
proposed regulations. PHMSA discussed some of the key comments received
in response to the NPRM, e.g., burdensome documentation requirements,
performance through people, plastic pipe failure reporting and excess
flow valves. These comments have been previously discussed in this
document.
    After careful consideration, the TPSSC voted unanimously to find
the NPRM (with proposed changes as discussed at the meeting) and
supporting regulatory evaluation technically feasible, reasonable,
practicable, and cost effective. A transcript of the teleconference is

available in the docket for this rulemaking. The following tables
summarize the major changes discussed at the meeting.

------------------------------------------------------------------------
     NPRM language          TAC recommendation      Final rule language
------------------------------------------------------------------------
               Burdensome Plan Documentation Requirements
------------------------------------------------------------------------
Sec.   192.1015 What     Limit documentation      Sec.   192.1011 What
 records must an          requirements to those    records must an
 operator keep?           in Sec.   192.1005 and   operator keep?
Except for the            Sec.   192.1007         An operator must
 performance measures    Greatly reduce            maintain records
 records required in      requirements in Sec.     demonstrating
 Sec.   192.1007, an      192.1015; focus on       compliance with the
 operator must            wording similar to       requirements of this
 maintain, for the        Sec.   192.1015(e)       subpart for at least
 useful life of the      Clarify requirement to    10 years. This must
 pipeline, records        retain record of past    include copies of
 demonstrating            versions of written IM   superseded integrity
 compliance with the      program                  management plans
 requirements of this    Language:                 developed under this
 subpart. At a minimum,  Sec.   192.1015 What      subpart.
 an operator must         records must an
 maintain the following   operator keep?
 records for review      (a) General records.
 during an inspection:    Operator must maintain
(a) A written IM          records demonstrating
 program in accordance    compliance with the
 with Sec.   192.1005;    requirements of this
(b) Documents             subpart for 10 years.
 supporting threat        This must include
 identification;          copies of superseded
(c) A written procedure   IM plans.
 for ranking the
 threats;
(d) Documents to
 support any decision,
 analysis, or process
 developed and used to
 implement and evaluate
 each element of the IM
 program;
(e) Records identifying
 changes made to the IM
 program, or its
 elements, including a
 description of the
 change and the reason
 it was made; and
(f) Records on
 performance measures.
 However, an operator
 must only retain
 records of performance
 measures for ten
 years.
------------------------------------------------------------------------
                     Reporting Plastic Pipe Failures
------------------------------------------------------------------------
Sec.   192.1009 What     Delete requirement       Sec.   192.1009 What
 must an operator        Continue to rely on       must an operator
 report when plastic      PPDC                     report when
 pipe fails?             Promote broad             compression couplings
Each operator must        communication of more    fail?
 report information       expansive set of PPDC   Each operator must
 relating to each         lessons                  report, on an annual
 material failure of     Retain reporting of       basis, information
 plastic pipe             compression couplings    related to failure of
 (including fittings,     failure                  compression
 couplings, valves and   Language:                 couplings, excluding
 joints) no later than   Sec.   192.1009 What      those that result
 90 days after failure.   must an operator         only in non-hazardous
 This information must    report when              leaks, as part of the
 include, at a minimum,   compression couplings    annual report
 location of the          fail?                    required by Sec.
 failure in the system,  Each operator must        191.11 beginning with
 nominal pipe size,       report information       the report submitted
 material type, nature    relating to each         March 15, 2011. This
 of failure including     failure of compression   information must
 any contribution of      couplings annually by    include, at a
 local pipeline           March 15, to PHMSA as    minimum, location of
 environment, pipe        part of the annual       the failure in the
 manufacturer, lot        report required by       system, nominal pipe
 number and date of       Sec.   191.11            size, material type,
 manufacture, and other   beginning with the       nature of failure
 information that can     report submitted March   including any
 be found in markings     15, 20xx [Date to        contribution of local
 on the failed pipe. An   depend on when final     pipeline environment,
 operator must send the   rule is issued].         coupling
 information report as                             manufacturer, lot
 indicated in Sec.                                 number and date of
 192.1013. An operator                             manufacture, and
 must also report this                             other information
 information to the                                that can be found in
 State pipeline safety                             markings on the
 authority in the State                            failed coupling. An
 where the gas                                     operator also must
 distribution pipeline                             report this
 is located.                                       information to the
                                                   state pipeline safety
                                                   authority if a state
                                                   exercises
                                                   jurisdiction over the
                                                   operator's pipeline.
------------------------------------------------------------------------
                       Performance Through People
------------------------------------------------------------------------
(b) In considering the   Delete requirement,      Requirement deleted,
 threat of                including reference to   including reference
 inappropriate            ``one call.''            to ``one call.''
 operation, the          Language:                (d) Identify and
 operator must evaluate  (d) Identify and          implement measures to
 the contribution of      implement measures to    address risks.
 human error to risk      address risks.           Determine and
 and the potential role   Determine and            implement measures
 of people in             implement measures       designed to reduce
 preventing and           designed to reduce the   the risks from
 mitigating the impact    risks from failure of    failure of its gas
 of events contributing   its gas distribution     distribution
 to risk. This            pipeline system. These   pipeline. These
 evaluation must also     measures must include    measures must include
 consider the             an effective leak        an effective leak
 contribution of          management program       management program
 existing DOT             (unless all leaks are    (unless all leaks are
 requirements             repaired when found)     repaired when found).
 applicable to the        and a damage
 operator's system        prevention program
 (e.g., Operator          required under Sec.
 Qualification, Drug      192.614 of this part.
 and Alcohol Testing)
 in mitigating risk.
------------------------------------------------------------------------

(d) Identify and         (f) Periodic Evaluation  (f) Periodic
 implement measures to    and Improvement. An      Evaluation and
 address risks.           operator must            Improvement. An
 Determine and            continually re-          operator must re-
 implement measures       evaluate threats and     evaluate threats and
 designed to reduce the   risks on its entire      risks on its entire
 risks from failure of    system and consider      pipeline and consider
 its gas distribution     the relevance of         the relevance of
 pipeline system. These   threats in one           threats in one
 measures must include    location to other        location to other
 implementing an          areas. In addition,      areas. Each operator
 effective leak           each operator must       must determine the
 management program and   periodically evaluate    appropriate period
 enhancing the            the effectiveness of     for conducting
 operator's damage        its program for          complete program
 prevention program       assuring individual      evaluations based on
 required under Sec.      performance to           the complexity of its
 192.614 of this part.    reassess the             system and changes in
 To address risks posed   contribution of human    factors affecting the
 by inappropriate         error to risk and to     risk of failure. An
 operation, an            identify opportunities   operator must conduct
 operator's written IM    to intervene to reduce   a complete program
 program must contain a   further the human        reevaluation at least
 separate section with    contribution to risk     every five years. The
 a heading `Assuring      (e.g., improve           operator must
 Individual               targeting of damage      consider the results
 Performance'. In that    prevention efforts).     of the performance
 section, an operator     Each operator must       monitoring in these
 must list risk           determine the            evaluations.
 management measures to   appropriate period for
 evaluate and manage      conducting complete
 the contribution of      program evaluations
 human error and          based on the
 intervention to risk     complexity of its
 (e.g., changes to the    system and changes in
 role or expertise of     factors affecting the
 people), and implement   risk of failure. An
 measures appropriate     operator must conduct
 to address the risk.     a complete program
 In addition, this        reevaluation at least
 section of the written   every five years. The
 IM program must          operator must consider
 consider existing        the results of the
 programs the operator    performance monitoring
 has implemented to       in these evaluations.
 comply with Sec.
 192.614 (damage
 prevention programs);
 Sec.   192.616 (public
 awareness); Subpart N
 of this Part
 (qualification of
 pipeline personnel),
 and 49 CFR Part 199
 (drug and alcohol
 testing).
                        Definition of ``Damage''
------------------------------------------------------------------------
Damage means any impact  Define ``excavation      Excavation Damage
 or exposure resulting    damage'' building on     means any impact that
 in the repair or         the definition in        results in the need
 replacement of an        DIRT--increases          to repair or replace
 underground facility,    clarity of reporting     an underground
 related appurtenance,    requirement.             facility due to a
 or materials            Language:                 weakening, or the
 supporting the          Excavation Damage means   partial or complete
 pipeline.                any impact or exposure   destruction, of the
                          that results in the      facility, including,
                          need to repair or        but not limited to,
                          replace an underground   the protective
                          facility due to the      coating, lateral
                          weakening or the         support, cathodic
                          partial or complete      protection or the
                          destruction of the       housing for the line
                          facility, including,     device or facility.
                          but not limited to,
                          the protective
                          coating, lateral
                          support, cathodic
                          protection or the
                          housing for the line
                          device or facility.
------------------------------------------------------------------------
                       Implementation Requirements
------------------------------------------------------------------------
Sec.   192.1005 What     Retain same period       Sec.   192.1005 What
 must a gas              Language:                 must a gas
 distribution operator   Sec.   192.1005 What      distribution operator
 (other than a master     must a gas               (other than a master
 meter or LPG operator)   distribution operator    meter or small LPG
 do to implement this     (other than a master     operator) do to
 subpart?                 meter or LPG operator)   implement this
(a) Dates. No later       do to implement this     subpart? No later
 than June 6, 2011 an     subpart?                 than August 2, 2011 a
 operator of a gas       (a) Dates. No later       gas distribution
 distribution pipeline    than June 6, 2011 an     operator must develop
 must develop and fully   operator of a gas        and implement an
 implement a written IM   distribution pipeline    integrity management
 program. The IM          must develop and fully   program that includes
 program must contain     implement a written IM   a written integrity
 the elements described   program. The IM          management plan as
 in Sec.   192.1007.      program must contain     specified in Sec.
(b) Procedures. An        the elements described   192.1007.
 operator's program       in Sec.   192.1007.
 must have written       (b) Procedures. An
 procedures describing    operator's program
 the processes for        must have written
 developing,              procedures for
 implementing and         developing,
 periodically improving   implementing and
 each of the required     periodically improving
 elements.                the required elements.
------------------------------------------------------------------------

               Alternative Intervals for Periodic Actions
------------------------------------------------------------------------
Sec.   192.1017 When     Clarify intent as to     Sec.   192.1013 When
 may an operator          responsibility for       may an operator
 deviate from required    decision on waiver       deviate from required
 periodic inspections     requests (States         periodic inspections
 under this part?         approve, no PHMSA        under this part?
(a) An operator may       review)                 (a) An operator may
 propose to reduce the   Need to make sure that    propose to reduce the
 frequency of periodic    it is clear that         frequency of periodic
 inspections and tests    overall level of         inspections and tests
 required in this part    safety is increased--    required in this part
 on the basis of the      not the level of         on the basis of the
 engineering analysis     safety on that           engineering analysis
 and risk assessment      particular line is       and risk assessment
 required by this         equal or higher.         required by this
 subpart. Operators may  System level rather       subpart.
 propose reductions       than individual line.   (b) An operator must
 only where they can     Language:                 submit its proposal
 demonstrate that the    Sec.   192.1017 When      to the PHMSA
 reduced frequency will   may an operator          Associate
 not significantly        deviate from required    Administrator for
 increase risk.           periodic inspections     Pipeline Safety or,
(b) An operator must      under this part?         in the case of an
 submit its proposal to  (a) An operator may       intrastate pipeline
 the PHMSA Associate      propose to reduce the    facility regulated by
 Administrator for        frequency of periodic    the State, the
 Pipeline Safety or the   inspections and tests    appropriate State
 State agency             required in this part    agency. The
 responsible for          on the basis of the      applicable oversight
 oversight of the         engineering analysis     agency may accept the
 operator's system.       and risk assessment      proposal on its own
 PHMSA, or the            required by this         authority, with or
 applicable State         subpart.                 without conditions
 oversight agency, may   Operators may propose     and limitations, on a
 accept the proposal,     reductions only where    showing that the
 with or without          they can demonstrate     operator's proposal,
 conditions and           that the reduced         which includes the
 limitations, on a        frequency will not       adjusted interval,
 showing that the         significantly increase   will provide an equal
 adjusted interval        risk.                    or greater overall
 provides a              (b) An operator must      level of safety.
 satisfactory level of    submit its proposal to  (c) An operator may
 pipeline safety.         the PHMSA Associate      implement an approved
                          Administrator for        reduction in the
                          Pipeline Safety or, in   frequency of a
                          the case of an           periodic inspection
                          intrastate pipeline      or test only where
                          facility regulated by    the operator has
                          the State, the           developed and
                          appropriate State        implemented an
                          agency. The applicable   integrity management
                          state oversight agency   program that provides
                          may accept the           an equal or improved
                          proposal on its own      overall level of
                          authority, with or       safety despite the
                          without conditions and   reduced frequency of
                          limitations, on a        periodic inspections.
                          showing that the
                          adjusted interval
                          provides a
                          satisfactory level of
                          pipeline safety.

        Program Requirements for Master Meters and LPG Operators
------------------------------------------------------------------------
(1) Infrastructure       Retain separate          (1) Knowledge. The
 knowledge. The           treatment; revise        operator must
 operator must            wording to include the   demonstrate knowledge
 demonstrate knowledge    requirement to ``rank    of its pipeline,
 of the system's          risks''                  which, to the extent
 infrastructure, which,  Language:                 known, should include
 to the extent known,    (1) Infrastructure        the approximate
 should include the       knowledge. The           location and material
 approximate location     operator must            of its pipeline. The
 and material of its      demonstrate knowledge    operator must
 distribution system.     of the system's          identify additional
 The operator must        infrastructure, which,   information needed
 identify additional      to the extent known,     and provide a plan
 information needed and   should include the       for gaining knowledge
 provide a plan for       approximate location     over time through
 gaining knowledge over   and material of its      normal activities
 time through normal      distribution system.     conducted on the
 activities.              The operator must        pipeline (for
(2) Identify threats.     identify additional      example, design,
 The operator must        information needed and   construction,
 consider, at minimum,    provide a plan for       operations or
 the following            gaining knowledge over   maintenance
 categories of threats    time through normal      activities).
 (existing and            activities.             (2) Identify threats.
 potential): corrosion,  (2) Identify threats.     The operator must
 natural forces,          The operator must        consider, at minimum,
 excavation damage,       consider, at minimum,    the following
 other outside force      the following            categories of threats
 damage, material or      categories of threats    (existing and
 weld failure,            (existing and            potential):
 equipment malfunction    potential): corrosion,   corrosion, natural
 and inappropriate        natural forces,          forces, excavation
 operation.               excavation damage,       damage, other outside
(3) Identify and          other outside force      force damage,
 implement measures to    damage, material or      material or weld
 mitigate risks. The      weld failure,            failure, equipment
 operator must            equipment malfunction    failure, and
 determine and            and inappropriate        incorrect operation.
 implement measures       operation.              (3) Rank risks. The
 designed to reduce the  (3) Rank risks. The       operator must
 risks from failure of    operator must evaluate   evaluate the risks to
 its pipeline system.     the risks to its         its pipeline and
(4) Measure               system and estimate      estimate the relative
 performance, monitor     the relative             importance of each
 results, and evaluate    importance of each       identified threat.
 effectiveness. The       identified threat.      (4) Identify and
 operator must develop   (4) Identify and          implement measures to
 and monitor              implement measures to    mitigate risks. The
 performance measures     mitigate risks. The      operator must
 on the number of leaks   operator must            determine and
 eliminated or repaired   determine and            implement measures
 on its pipeline system   implement measures       designed to reduce
 and their causes.        designed to reduce the   the risks from
(5) Periodic evaluation   risks from failure of    failure of its
 and improvement. The     its pipeline system.     pipeline.
 operator must           (5) Measure              (5) Measure
 determine the            performance, monitor     performance, monitor
 appropriate period for   results, and evaluate    results, and evaluate
 conducting IM program    effectiveness. The       effectiveness. The
 evaluations based on     operator must develop    operator must
 the complexity of its    and monitor              monitor, as a
 system and changes in    performance measures     performance measure,
 factors affecting the    on the number of leaks   the number of leaks
 risk of failure. An      eliminated or repaired   eliminated or
 operator must re-        on its pipeline system   repaired on its
 evaluate its entire      and their causes.        pipeline and their
 program at least every  (6) Periodic evaluation   causes.
 five years. The          and improvement. The    (6) Periodic
 operator must consider   operator must            evaluation and
 the results of the       determine the            improvement. The
 performance monitoring   appropriate period for   operator must
 in these evaluations.    conducting IM program    determine the
                          evaluations based on     appropriate period
                          the complexity of its    for conducting IM
                          system and changes in    program evaluations
                          factors affecting the    based on the
                          risk of failure. An      complexity of its
                          operator must re-        pipeline and changes
                          evaluate its entire      in factors affecting
                          program at least every   the risk of failure.
                          five years. The          An operator must re-
                          operator must consider   evaluate its entire
                          the results of the       program at least
                          performance monitoring   every five years. The
                          in these evaluations.    operator must
                                                   consider the results
                                                   of the performance
                                                   monitoring in these
                                                   evaluations.

                      Excess Flow Valve Requirement
------------------------------------------------------------------------
Sec.   192.1011 When     Move provision to        Sec.   192.383 Excess
 must an Excess Flow      Subpart H this will      flow valve
 Valve (EFV) be           lead to requiring        installation.
 installed?               implementation by MM;   (a) Definitions. As
(a) General               Explicitly address EFV   used in this section:
 requirements. This       installation            Replaced service line
 section only applies     requirement on branch    means a natural gas
 to new or replaced       service lines--clarify   service line where
 service lines serving    that EFVs are required   the fitting that
 single-family            for service lines        connects the service
 residences. An EFV       servicing single         line to the main is
 installation must        family residences.       replaced or the
 comply with the         Language:                 piping connected to
 requirements in Sec.    Sec.   192.383 Excess     this fitting is
 192.381.                 flow valve               replaced.
(b) Installation          installation.           Service line serving
 required. The operator  (a) Definitions. As       single-family
 must install an EFV on   used in this section:    residence means a
 the service line        Replaced service line     natural gas service
 installed or entirely    means a natural gas      line that begins at
 replaced after March     service line where the   the fitting that
 4, 2010, unless one or   fitting that connects    connects the service
 more of the following    the service line to      line to the main and
 conditions is present:   the main line is         serves only one
(1) The service line      replaced or the piping   single-family
 does not operate at a    connected to this        residence.
 pressure of 10 psig or   fitting is replaced.    (b) Installation
 greater throughout the  Service line serving      required. An excess
 year;                    single-family            flow valve (EFV)
(2) The operator has      residence means a        installation must
 prior experience with    natural gas service      comply with the
 contaminants in the      line beginning at the    performance standards
 gas stream that could    fitting that connects    in Sec.   192.381.
 interfere with the       the service line to      The operator must
 EFV's operation or       the main and serving     install an EFV on any
 cause loss of service    only one single-family   new or replaced
 to a residence;          residence.               service line serving
(3) An EFV could         (b) Installation          a single-family
 interfere with           required. An EFV         residence after
 necessary operation or   installation must        February 2, 2010,
 maintenance              comply with the          unless one or more of
 activities, such as      performance standards    the following
 blowing liquids from     in Sec.   192.381. The   conditions is
 the line; or             operator must install    present:
(4) An EFV meeting        an EFV on new or        (1) The service line
 performance              replaced service lines   does not operate at a
 requirements in Sec.     serving single-family    pressure of 10 psig
 192.381 is not           residences after         or greater throughout
 commercially available   February 2, 2010,        the year;
 to the operator.         unless one or more of   (2) The operator has
                          the following            prior experience with
                          conditions is present:   contaminants in the
                         (1) The service line      gas stream that could
                          does not operate at a    interfere with the
                          pressure of 10 psig or   EFV's operation or
                          greater throughout the   cause loss of service
                          year;                    to a residence;
                         (2) The operator has     (3) An EFV could
                          prior experience with    interfere with
                          contaminants in the      necessary operation
                          gas stream that could    or maintenance
                          interfere with the       activities, such as
                          EFV's operation or       blowing liquids from
                          cause loss of service    the line; or
                          to a residence;         (4) An EFV meeting
                         (3) An EFV could          performance standards
                          interfere with           in Sec.   192.381 is
                          necessary operation or   not commercially
                          maintenance              available to the
                          activities, such as      operator.
                          blowing liquids from    (c) Reporting. Each
                          the line; or             operator must, on an
                         (4) An EFV meeting        annual basis, report
                          performance              the number of EFVs
                          requirements in Sec.     installed pursuant to
                          192.381 is not           this section as part
                          commercially available   of the annual report
                          to the operator.         required by Sec.
                                                   191.11.
------------------------------------------------------------------------

V. Final Rule

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

Section-by-Section Analysis

Section 192.383. Excess flow valve installation
    This section currently requires that operators notify new customers
of the availability of excess flow valves (EFV) and install a valve if
the customer agrees to pay for the installation and any subsequent
maintenance costs. This requirement has been superseded by the
statutory mandate that PHMSA require operators to install such valves
in all new and replaced residential service lines serving single-family
residences. This section is revised to replace the notification
requirement with the new requirement to install. Installation is not
required if operating pressure is less than 10 psig, if the operator
has experience with contaminants that would interfere with valve
operation, if an EFV is likely to interfere with necessary operation or
maintenance activities, or if an EFV meeting the performance standards
of Sec.  192.381 is not commercially available. The revised section
also requires that each operator report the number of EFVs installed
during each year in the annual report already required (Sec.  192.11).
    A definition for ``service line serving single-family residence''
is added.

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

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

consistent definition will be important to assuring that this data is
useful. Several comments suggested that PHMSA adopt the Gas Piping
Technology Committee's (GPTC) Guide definition for a Grade 1 leak. This
definition is already used by many operators to define hazardous leaks.
PHMSA has followed the suggestion of the comments. The change to this
section adds a definition similar to that of the GPTC Guide for Grade 1
leaks.
    A definition for ``integrity management program'' is added. An
integrity management program, as used within this rule, is an overall
approach by an operator to ensure the integrity of its distribution
system. The program includes an integrity management plan, which is
revised periodically. The program also encompasses compliance with
other relevant regulations. For some operators, the program may involve
the selection of certain materials or adherence to professional
standards that are not mandated by Federal regulation.
    A definition for ``integrity management plan'' is added. An
integrity management plan is a written explanation of the mechanisms
the operator will use to implement its integrity management program and
to ensure compliance with this rule.
    A definition for ``small LPG operators'' is added. The new rule
requires LPG operators with LPG distribution systems serving 100 or
more customers to comply with the full integrity management program
requirements. Small LPG operators, those with LPG distribution systems
serving less than 100 customers from a single source must comply with
the same requirements as master meter operators.
Section 192.1003. What do the regulations in this subpart cover?
    This section describes the content of the new subpart and specifies
which operators must comply with which sections. Master meter operators
and small LPG operators are not required to meet all of the
requirements applicable to other operators of distribution pipelines.
The content of IM programs required of these operators is similar
(described below), but somewhat simpler. Documentation requirements for
these operators are different, consistent with their treatment in the
rest of Part 192.
Section 192.1005. What must a gas distribution operator (other than a
master meter or small LPG operator) do to implement this subpart?
    This section requires operators of gas distribution pipelines and
of LPG distribution pipelines serving 100 or more customers from a
single source to develop and implement an IM program no later than 18
months after the effective date of this final rule. PHMSA recognizes
that IM programs are likely to improve as operators gain experience.
This does not mean, however, that it is acceptable for programs
developed and implemented within 18 months to be incomplete. Those
programs should address all required elements. PHMSA expects operators
to revise their plans, following initial implementation, to reflect
lessons that they learn through implementing them.
Section 192.1007. What are the required elements of an integrity
management (IM) plan?
    This section defines the minimum elements that IM plans developed
by distribution pipeline operators (other than master meter and small
LPG operators) must address. A plan must have written procedures for
developing and implementing the following elements:
    a. Knowledge. This section requires an operator to develop an
understanding of its distribution pipeline. An operator must identify
the characteristics of its pipeline's design and operations, and of the
environment in which it operates, which are necessary to assess
applicable threats and risks. This must include considering information
gained from past design, operations, and maintenance.
    This section requires that operators develop their understanding
from reasonably available information. The rule does not require
operators to retrieve many years of archived records or to conduct
additional investigations (e.g., excavation) to discover information
about the pipeline. Operators have considerable knowledge of their
pipeline to support routine operations and maintenance, but this
information may be distributed throughout the company, in possession of
groups responsible for individual functions. Operators must assemble
this information to the extent necessary to support development and
implementation of their IM program.
    PHMSA recognizes that there may be gaps in the knowledge an
operator has when it develops its initial IM plan. Operators must
identify these gaps and the additional information needed to improve
their understanding. Operators are required to provide a plan for
gaining that information over time through its normal activities of
operating and maintaining their pipeline (e.g., collecting information
about buried components when portions of the pipeline must be excavated
for other reasons). Operators must also develop a process by which the
program will be periodically reviewed and refined, as needed.
    b. Identify threats. Identification of the threats that affect, or
could potentially affect, a distribution pipeline is key to assuring
its integrity. Knowledge of applicable threats allows operators to
evaluate the risks they pose and to rank those risks, allowing safety
resources to be applied where they will be most effective.
    This section requires that operators consider the general
categories of threats that must now be reported on annual reports.
Reporting has been required for many years, meaning that data are
available regarding these threat categories. Operators are required to
consider reasonably available information to identify threats that
affect their pipeline or that could potentially affect it (e.g.,
landslides in a hilly area with loose soils even if no landslide has
been experienced). The section specifies data sources resulting from
normal operation and maintenance that operators may consider in
evaluating threats.
    c. Evaluate and rank risk. This section requires that an operator
evaluate the identified threats to determine their relative importance
and rank the risks associated with its pipeline. Operators must
consider the likelihood of threats as well as the consequences of a
failure that might result from each threat. Consideration of
consequences is important to assure that risks are properly ranked. A
potential accident of relatively low likelihood but that would produce
significant consequences may be a higher risk than an accident with
somewhat greater likelihood but that cannot produce major consequences.
    Operators may subdivide their pipeline into regions for purposes of
this analysis. Such division may be appropriate when factors relevant
to a threat vary within the pipeline. For example, the threat of
corrosion is not applicable to portions of the pipeline made of plastic
materials. The corrosion threat likely would be of different importance
to metal portions of the pipeline that are coated and cathodically
protected than it would be to any portions that are bare or
unprotected. Operators are not, however, required to divide their

pipelines for purposes of analyzing risks.
    d. Identify and implement measures to address risks. Operator IM
programs must include measures designed to reduce the risk of failure
from identified threats. These measures must include an effective leak
management program (which most operators are already implementing)
unless the operator already repairs all leaks when found.
    e. Measure performance, monitor results, and evaluate
effectiveness. Measuring performance is a key element of IM programs.
This section requires operators to develop performance measures,
including some that are specified for use by all operators. Measuring
performance periodically allows operators to determine whether actions
being taken to address threats are effective, or whether different or
additional actions are needed.
    f. Periodic Evaluation and Improvement. This element requires
operators to periodically re-evaluate risks on their entire pipeline
and to consider the relevance of threats in one location to other
locations. Operators must consider the results of their performance
monitoring in these evaluations, which must be performed at least once
every five years. An operator must determine an appropriate period for
conducting a complete program evaluation based on the complexity of its
system. An operator should conduct a program evaluation any time there
are changes in factors that would affect the risk of failure.
    g. Report results. This section requires that operators include in
their annual reports some of the performance measures required by the
rule. PHMSA will use this data to evaluate the overall effectiveness of
distribution IM requirements. (Note that one of the measures required
to be reported--all leaks repaired, by cause--has historically been
required on the annual report).
Section 192.1009. What must an operator report when compression
couplings fail?
    Compression couplings are mechanical fittings used to connect
sections of pipe. Such couplings are often used to connect plastic pipe
to metal pipe. Failure of compression couplings has resulted in a
number of serious accidents on distribution pipelines. This section
requires that operators report information related to failure of
compression couplings (excluding failures that result only in non-
hazardous leaks) on their annual report. PHMSA will use this data to
evaluate the scope of problems related to compression couplings and
will determine if changes to the regulations are appropriate to help
prevent incidents caused by coupling failure.
Section 192.1011. What records must an operator keep?
    This section requires that operators keep records for 10 years that
demonstrate compliance with the requirements of this new subpart. The
records must include superseded copies of IM plans.
Section 192.1013. When may an operator deviate from required periodic
inspections under this part?
    The operator's evaluation of threats and risk may identify
additional actions that could be effective in reducing risk on
distribution pipelines. This section allows operators to reduce the
frequency of actions now required by this Part to be conducted
periodically, to realign safety resources to better address risks.
Operators must receive approval from their safety regulator (PHMSA or
state, as appropriate) before they can reduce the required frequency,
and must demonstrate that the overall effect of their proposed change
will be an equal or greater level of pipeline safety.
    This section requires an operator to submit a proposal that
explains the desired alternative frequency for a required periodic
inspection and that explains other actions the operator will take as
part of the integrity management program to ensure an equal or greater
overall level of pipeline safety. A proposal should include sufficient
information to explain how the IM plan and IM program would be modified
if the proposal is approved. States will use their authority to approve
reductions in the frequency of safety actions otherwise required by
Part 192.
Section 192.1015. What must a master meter or small liquefied petroleum
gas (LPG) operator do to implement this subpart?
    Most master meter operators are small entities and operating their
gas distribution pipelines is not their principal occupation. These
operators typically have limited on-staff technical pipeline expertise.
These operators have historically been treated differently within Part
192. In particular, they have been subject to more limited
documentation requirements. For example, master meter operators and
operators of LPG distribution pipelines that serve fewer than 100
customers from a single source are not required to submit annual
reports.
    This section prescribes IM requirements applicable to these smaller
operators. The major elements that these operators are required to
include in their IM plans are the same as those in Sec.  192.1007
applicable to other operators. The details of the elements are
simplified somewhat, to reflect both the relative simplicity of these
pipelines and the limited capability of the operators. For example, the
required knowledge of their pipeline is focused on the approximate
location and material of which it is constructed and required
documentation of this knowledge is limited to documents showing the
location and material of piping and appurtenances that are installed
after the effective date of their IM programs and, to the extent known,
in existence when the program becomes effective. These operators are
not required to submit performance measures, which is consistent with
their prior treatment with respect to annual reports.
    PHMSA expects that the IM plans developed by these operators will
be simpler than those developed by operators of more complex
distribution pipelines. PHMSA is developing guidance suitable for use
by master meter and small LPG operators to develop simple IM plans for
their pipelines. This guidance will be made available via PHMSA's web
site after this final rule is published.

VI. Regulatory Analyses and Notices

A. Statutory/Legal Authority for This Rulemaking

    This final rule is published under the authority of the Federal
Pipeline Safety Law (49 U.S.C. 60101 et seq.). Section 60102 authorizes
the Secretary of Transportation to issue regulations governing design,
installation, inspection, emergency plans and procedures, testing,
construction, extension, operation, replacement, and maintenance of
pipeline facilities. The integrity management program regulations are
issued under this authority and address NTSB and DOT Inspector General
recommendations. This rulemaking also carries out the mandates
regarding distribution integrity management and excess flows valves
under section 9 of the Pipeline Inspection, Protection, Enforcement,
and Safety Act of 2006 (Pub. L. No. 109-468, Dec. 29, 2006, codified at
49 U.S.C. Sec.  60109(e)).

B. Executive Order 12866 and DOT Regulatory Policies and Procedures

    Executive Order 12866 directs all Federal agencies to consider the
costs and benefits of ``significant regulatory actions.'' Federal
agencies are directed

to develop a formal Regulatory Impact Analysis consistent with OMB
Circular A-4 for all ``economically significant'' rules, or those rules
estimated to have an impact of $100 million or more in any one year.
    DOT considers this an ``economically significant'' regulatory
action under section 3(f)(1) of Executive Order 12866 (58 FR 51735;
October 4, 1993). This final rule is also significant under DOT's
regulatory policies and procedures (44 FR 11034; February 26, 1979).
PHMSA prepared a Regulatory Evaluation for this final rule and placed
it in the public docket.
    The rule's requirements would affect an estimated 9,343 natural gas
operators with a combined total of 1,138,000 miles of mains and
60,970,000 services. Of these operators, 201 are large local gas
utilities, 1,090 are small local gas utilities, 52 are LPG operators
servicing 100 or more customers from a single source, and approximately
8,000 are master meter and small LPG systems. PHMSA determined that the
approximately 1,142 gas operators and the 8,000 master meter operators
and LPG systems are small.
    The monetized benefits resulting from the final rule are estimated
to be between $165 million and $170 million per year. Those benefits
include:
     Reductions in the consequences of reportable incidents
     Reductions in the consequences of non-reportable incidents
     A reduction in the probability of a major catastrophic
incident
     Reductions in lost natural gas
     Reductions in emergency response costs
     Reductions in evacuations
     Reductions in dig-ins impacting non-gas underground
facilities
     The end of the existing EFV notification requirement
    The costs of the final rule are estimated to be $130 million in the
first year and $101 million in each subsequent year. Those costs cover:
     Development of an IM program
     Implementation of the IM program (data acquisition and
analysis)
     Mitigation of risks (leak management, excess flow valve
installation and other)
     Reporting to PHMSA and State Regulators
     Recordkeeping
     Management of the IM program.
    The Regulatory Impact Analyses (RIA) finds that the rule is not
expected to adversely affect the economy or the environment. The
analysis finds that, for those costs and benefits that can be
quantified, the present value of net benefits is expected to be between
$21 million and $1.6 billion over a 50-year period after all of the
requirements are implemented. Furthermore, the rule is expected yield
positive net benefits if it results in eliminating only approximately
12.2 percent of the societal costs the first year, and about 9.5
percent in subsequent years.

C. Regulatory Flexibility Act

    Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), PHMSA
must consider whether a rulemaking would have a significant effect on a
substantial number of small entities. The IM program requirements in
this rule apply to gas distribution pipeline operators and require
operators of gas distribution pipelines to develop and implement IM
plans that will better assure the integrity of their pipeline systems.
    Many gas distribution pipeline operators meet the Small Business
Administration's small business definition of 500 or fewer employees
for natural gas distribution operators under North American Industry
Classification System (NAICS) 221210. PHMSA estimates that the rule
will affect approximately 9,090 small operators. These small operators
can be separated into two categories: (1) Local gas distribution
utilities with 12,000 or fewer services and (2) master meter and LPG
systems. PHMSA estimates there are 1,090 small operators among the
local gas distribution utilities with 12,000 or fewer services and
approximately 8,000 master meter and LPG systems, all of which are
small.
    Furthermore, PHMSA estimates the rule will cost each of the 1,090
small operators and the 52 LPG operators serving 100 or more customers
from a single source, on average, approximately $33,600 in the first
year and $15,400 in each subsequent year. PHMSA also estimates that the
rule will cost each of the 8,000 master meter and small LPG systems, on
average, approximately $2,900 in the first year and $1,100 in each
subsequent year. PHMSA does not have information on the operators'
revenues and cannot estimate the economic impact the costs will have.
The costs associated with the rule may be significant for at least some
of the small entities, if the costs exceed 1 percent of the revenues.
Therefore, PHMSA believes that the rule could result in a significant
adverse economic impact for some of the smallest affected entities.
    PHMSA has minimized costs for these small operators. As mentioned
earlier, small operators' IM programs will be subject to more limited
documentation requirements. PHMSA is also providing guidance for small
operators. Additionally, industry is undertaking a number of
initiatives that will help small entities comply with the proposed
rule, including the preparation of guidance materials and a model IM
program for distribution pipeline operators.

D. Paperwork Reduction Act

    The Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.)
addresses the collection of information by the Federal government from
individuals, small businesses and state and local governments and seeks
to minimize the burdens such information collection requirements might
impose. A collection of information includes providing answers to
identical questions posed to, or identical reporting or record-keeping
requirements imposed on ten or more persons, other than agencies,
instrumentalities, or employees of the United States. In accordance
with the requirements of the Paperwork Reduction Act, agencies may not
conduct or sponsor, and the respondent is not required to respond to,
an information collection unless it displays a currently valid Office
of Management and Budget (OMB) control number.
    This rule requires operators to report four distribution integrity
management program (DIMP) performance measures in the annual report
(Incident and Annual Reports for Gas Pipeline Operators. OMB Control
Number: 2137-0522). All data required under this rule to be reported
will be reported via the annual report.
    One of the measures required to be reported--all leaks repaired, by
cause--has historically been required as part of annual reports. The
other information to be reported will require modifications to the
annual report form. Therefore, PHMSA is also using this rulemaking as a
60-day notice to revise the annual report information collection, OMB
Control Number 2137-0522. PHMSA seeks comment on the proposed modified
annual report form, which is available in the docket for this
rulemaking.
    In addition, the rule also requires operators to report, as part of
the annual report, detailed information regarding compression coupling
failures. PHMSA has created a compression coupling failure addendum to
be submitted with the annual report form, as needed. PHMSA also seeks
comment on the proposed compression coupling failure addendum form.
This form will also be part of the revised 2137-0522 information
collection and is available in the docket for this rulemaking.

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

E. Executive Order 13084

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

F. Executive Order 13132

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

G. Executive Order 13211

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

H. Unfunded Mandates

    PHMSA estimates that this final rule does impose an unfunded
mandate under the 1995 Unfunded Mandates Reform Act (UMRA). PHMSA
estimates the rule to cost operators $155.1 million in the first year
of the regulations, which is higher than the $100 million threshold
(adjusted for inflation, currently estimated to be $141.3 million) in
any one year. The Regulatory Impact Analysis performed under EO 12866
requirements also meets the analytical requirements under UMRA, and
PHMSA has concluded the approach taken in this regulation is the least
burdensome alternative for achieving our rule's objectives.

I. National Environmental Policy Act

    PHMSA analyzed this final rule in accordance with section 102(2)(c)
of the National Environmental Policy Act (42 U.S.C. 4332), the Council
on Environmental Quality regulations (40 CFR 1500-1508), and DOT Order
5610.1C, and has determined that this action will not significantly
affect the quality of the human environment. PHMSA conducted an
Environmental Assessment on the NPRM and did not receive any comment on
the preliminary analysis. The Environmental Assessment is available for
review in the Docket.

List of Subjects in 49 CFR Part 192

    Integrity management, Pipeline safety, Reporting and recordkeeping
requirements.

0
In consideration of the foregoing, PHMSA is amending Part 192 of Title
49 of the Code of Federal Regulations as follows:

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

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

    Authority:  49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110,
60113, 60116, 60118, and 60137; and 49 CFR 1.53.

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2. Section 192.383 is revised to read as follows:

Sec.  192.383  Excess flow valve installation.

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(a) Definitions. As used in this section:
    Replaced service line means a natural gas service line where the
fitting that connects the service line to the main is replaced or the
piping connected to this fitting is replaced.
    Service line serving single-family residence means a natural gas
service line that begins at the fitting that connects the service line
to the main and serves only one single-family residence.
    (b) Installation required. An excess flow valve (EFV) installation
must comply with the performance standards in Sec.  192.381. The
operator must install an EFV on any new or replaced service line
serving a single-family residence after February 2, 2010, unless one or
more of the following conditions is present:
    (1) The service line does not operate at a pressure of 10 psig or
greater throughout the year;
    (2) The operator has prior experience with contaminants in the gas
stream that could interfere with the EFV's operation or cause loss of
service to a residence;
    (3) An EFV could interfere with necessary operation or maintenance
activities, such as blowing liquids from the line; or
    (4) An EFV meeting performance standards in Sec.  192.381 is not
commercially available to the operator.
    (c) Reporting. Each operator must, on an annual basis, report the
number of EFVs installed pursuant to this section as part of the annual
report required by Sec.  191.11.
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3. In Part 192, a new subpart P is added to read as follows:
Subpart P--Gas Distribution Pipeline Integrity Management (IM)
Sec.
192.1001 What definitions apply to this subpart?
192.1003 What do the regulations in this subpart cover?
192.1005 What must a gas distribution operator (other than a master
meter or small LPG operator) do to implement this subpart?
192.1007 What are the required elements of an integrity management
plan?
192.1009 What must an operator report when compression couplings
fail?
192.1011 What records must an operator keep?
192.1013 When may an operator deviate from required periodic
inspections of this part?
192.1015 What must a master meter or small liquefied petroleum gas
(LPG) operator do to implement this subpart?

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

Sec.  192.1001  What definitions apply to this subpart?

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

Sec.  192.1003  What do the regulations in this subpart cover?

    General. This subpart prescribes minimum requirements for an IM
program for any gas distribution pipeline covered under this part,
including liquefied petroleum gas systems. A gas distribution operator,
other than a master meter operator or a small LPG operator, must follow
the requirements in Sec. Sec.  192.1005-192.1013 of this subpart. A
master meter operator or small LPG operator of a gas distribution
pipeline must follow the requirements in Sec.  192.1015 of this
subpart.

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

    No later than August 2, 2011 a gas distribution operator must
develop and implement an integrity management program that includes a
written integrity management plan as specified in Sec.  192.1007.

Sec.  192.1007  What are the required elements of an integrity
management plan?

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

likely would be effective in reducing risk.
    (d) Identify and implement measures to address risks. Determine and
implement measures designed to reduce the risks from failure of its gas
distribution pipeline. These measures must include an effective leak
management program (unless all leaks are repaired when found).
    (e) Measure performance, monitor results, and evaluate
effectiveness.
    (1) Develop and monitor performance measures from an established
baseline to evaluate the effectiveness of its IM program. An operator
must consider the results of its performance monitoring in periodically
re-evaluating the threats and risks. These performance measures must
include the following:
    (i) Number of hazardous leaks either eliminated or repaired as
required by Sec.  192.703(c) of this subchapter (or total number of
leaks if all leaks are repaired when found), categorized by cause;
    (ii) Number of excavation damages;
    (iii) Number of excavation tickets (receipt of information by the
underground facility operator from the notification center);
    (iv) Total number of leaks either eliminated or repaired,
categorized by cause;
    (v) Number of hazardous leaks either eliminated or repaired as
required by Sec.  192.703(c) (or total number of leaks if all leaks are
repaired when found), categorized by material; and
    (vi) Any additional measures the operator determines are needed to
evaluate the effectiveness of the operator's IM program in controlling
each identified threat.
    (f) Periodic Evaluation and Improvement. An operator must re-
evaluate threats and risks on its entire pipeline and consider the
relevance of threats in one location to other areas. Each operator must
determine the appropriate period for conducting complete program
evaluations based on the complexity of its system and changes in
factors affecting the risk of failure. An operator must conduct a
complete program re-evaluation at least every five years. The operator
must consider the results of the performance monitoring in these
evaluations.
    (g) Report results. Report, on an annual basis, the four measures
listed in paragraphs (e)(1)(i) through (e)(1)(iv) of this section, as
part of the annual report required by Sec.  191.11. An operator also
must report the four measures to the state pipeline safety authority if
a state exercises jurisdiction over the operator's pipeline.

Sec.  192.1009  What must an operator report when compression couplings
fail?

    Each operator must report, on an annual basis, information related
to failure of compression couplings, excluding those that result only
in non-hazardous leaks, as part of the annual report required by Sec.
191.11 beginning with the report submitted March 15, 2011. This
information must include, at a minimum, location of the failure in the
system, nominal pipe size, material type, nature of failure including
any contribution of local pipeline environment, coupling manufacturer,
lot number and date of manufacture, and other information that can be
found in markings on the failed coupling. An operator also must report
this information to the state pipeline safety authority if a state
exercises jurisdiction over the operator's pipeline.

Sec.  192.1011  What records must an operator keep?

    An operator must maintain records demonstrating compliance with the
requirements of this subpart for at least 10 years. The records must
include copies of superseded integrity management plans developed under
this subpart.

Sec.  192.1013  When may an operator deviate from required periodic
inspections under this part?

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

Sec.  192.1015  What must a master meter or small liquefied petroleum
gas (LPG) operator do to implement this subpart?

    (a) General. No later than August 2, 2011 the operator of a master
meter system or a small LPG operator must develop and implement an IM
program that includes a written IM plan as specified in paragraph (b)
of this section. The IM program for these pipelines should reflect the
relative simplicity of these types of pipelines.
    (b) Elements. A written integrity management plan must address, at
a minimum, the following elements:
    (1) Knowledge. The operator must demonstrate knowledge of its
pipeline, which, to the extent known, should include the approximate
location and material of its pipeline. The operator must identify
additional information needed and provide a plan for gaining knowledge
over time through normal activities conducted on the pipeline (for
example, design, construction, operations or maintenance activities).
    (2) Identify threats. The operator must consider, at minimum, the
following categories of threats (existing and potential): Corrosion,
natural forces, excavation damage, other outside force damage, material
or weld failure, equipment failure, and incorrect operation.
    (3) Rank risks. The operator must evaluate the risks to its
pipeline and estimate the relative importance of each identified
threat.
    (4) Identify and implement measures to mitigate risks. The operator
must determine and implement measures designed to reduce the risks from
failure of its pipeline.
    (5) Measure performance, monitor results, and evaluate
effectiveness. The operator must monitor, as a performance measure, the
number of leaks eliminated or repaired on its pipeline and their
causes.
    (6) Periodic evaluation and improvement. The operator must
determine the appropriate period for conducting IM program evaluations
based on the complexity of its pipeline and changes in factors
affecting the risk of failure. An operator must re-evaluate its entire
program at least every five years. The operator must consider the
results of the performance monitoring in these evaluations.
    (c) Records. The operator must maintain, for a period of at least
10 years, the following records:
    (1) A written IM plan in accordance with this section, including
superseded IM plans;
    (2) Documents supporting threat identification; and
    (3) Documents showing the location and material of all piping and
appurtenances that are installed after the effective date of the
operator's IM program and, to the extent known, the location and
material of all pipe and

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

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

BILLING CODE 4910-60-P


[Federal Register Volume 76, Number 65 (Tuesday, April 5, 2011)]
[Notices]
[Pages 18753-18754]
[FR Doc No: 2011-8027]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. PR11-97-000]

Jefferson Island Storage & Hub, L.L.C.; Notice of Filing

    Take notice that on March 28, 2011, Jefferson Island Storage & Hub,
L.L.C. (Jefferson Island) submitted a revised Statement of Operating
Conditions (SOC) for services provided under section 311 of the Natural
Gas Policy Act of 1978 (``NGPA''). Jefferson Island proposes to revise
its SOC to provide its customers the option to use pooling points as
additional points of receipt and/or delivery under their service
agreements, as more fully described in the application.
    Any person desiring to participate in this rate filing must file in
accordance with Rules 211 and 214 of the Commission's Rules of Practice
and Procedure (18 CFR 385.211 and 385.214). Protests will be considered
by the Commission in determining the appropriate action to be taken,
but will not serve to make protestants parties to the proceeding. Any
person wishing to become a party must file a notice of intervention or
motion to intervene, as appropriate. Such notices, motions, or protests
must be filed on or before the date as indicated below. Anyone filing
an intervention or protest must serve a copy of that document on the
Applicant.

Anyone filing an intervention or protest on or before the intervention
or protest date need not serve motions to intervene or protests on
persons other than the Applicant.
    The Commission encourages electronic submission of protests and
interventions in lieu of paper using the ``eFiling'' link at http://www.ferc.gov. Persons unable to file electronically should submit an
original and 7 copies of the protest or intervention to the Federal
Energy Regulatory Commission, 888 First Street, NE., Washington, DC
20426.
    This filing is accessible online at http://www.ferc.gov, using the
``eLibrary'' link and is available for review in the Commission's
Public Reference Room in Washington, DC. There is an ``eSubscription''
link on the Web site that enables subscribers to receive e-mail
notification when a document is added to a subscribed docket(s). For
assistance with any FERC Online service, please e-mail
<EMAIL_ADDRESS>or call<PHONE_NUMBER> (toll free). For
TTY, call<PHONE_NUMBER>.
    Comment Date: 5 p.m. Eastern Time on Friday, April 8, 2011.

    Dated: March 30, 2011.
Kimberly D. Bose,
Secretary.
[FR Doc. 2011-8027 Filed 4-4-11; 8:45 am]
BILLING CODE 6717-01-P