Document ID: PHMSA-RSPA-2004-19854-0258
Agency: phmsa
Document Type: Rule
Title: Pipeline Safety: Integrity Management Program for Gas Distribution Pipelines
Posted Date: 2009-12-04T05:00Z

[Federal Register: December 4, 2009 (Volume 74, Number 232)]
[Rules and Regulations]               
[Page 63905-63936]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr04de09-29]                         

[[Page 63905]]

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Part III

Department of Transportation

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Pipeline and Hazardous Materials Safety Administration

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49 CFR Part 192

Pipeline Safety: Integrity Management Program for Gas Distribution 
Pipelines; Final Rule

[[Page 63906]]

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Part 192

[Docket No. PHMSA-RSPA-2004-19854; Amdt. 192-113]
RIN 2137-AE15

 
Pipeline Safety: Integrity Management Program for Gas 
Distribution Pipelines

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

ACTION: Final rule.

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SUMMARY: PHMSA is amending the Federal Pipeline Safety Regulations to 
require operators of gas distribution pipelines to develop and 
implement integrity management (IM) programs. The purpose of these 
programs is to enhance safety by identifying and reducing pipeline 
integrity risks. The IM programs required by this rule are similar to 
those required for gas transmission pipelines, but tailored to reflect 
the differences in and among distribution pipelines. Based on the 
required risk assessments and enhanced controls, the rule also allows 
for risk-based adjustment of prescribed intervals for leak detection 
surveys and other fixed-interval requirements in the agency's existing 
regulations for gas distribution pipelines. To further minimize 
regulatory burdens, the rule establishes simpler requirements for 
master meter and small liquefied petroleum gas (LPG) operators, 
reflecting the relatively lower risk of these small pipelines.
    In accordance with Federal law, the rule also requires operators to 
install excess flow valves on new and replaced residential service 
lines, subject to feasibility criteria outlined in the rule.
    This final rule addresses statutory mandates and recommendations 
from the DOT's Office of the Inspector General (OIG) and stakeholder 
groups.

DATES: Effective Date: This Final Rule takes effect February 2, 2010.
    Comment Date: Interested persons are invited to submit comment on 
the provisions for reporting failures of compression couplings by 
January 4, 2010. At the end of the comment period, we will publish a 
document modifying these provisions or a document stating that the 
provisions will remain unchanged.

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

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

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

SUPPLEMENTARY INFORMATION: 

I. Background

    Existing integrity management regulations cover operators of 
hazardous liquid pipelines (49 CFR 195.452, published at 65 FR 75378 
and 67 FR 2136) and gas transmission pipelines (49 CFR 192, Subpart O, 
published at 68 FR 69778). These regulations require that operators of 
these pipelines develop and follow individualized integrity management 
(IM) programs, in addition to PHMSA's core pipeline safety regulations. 
The IM approach was designed to promote continuous improvement in 
pipeline safety by requiring operators to identify and invest in risk 
control measures beyond core regulatory requirements.
    PHMSA published a Notice of Proposed Rulemaking (NPRM) on June 25, 
2008, (73 FR 36015) to extend its integrity management approach to the 
largest segment of the Nation's pipeline network--the gas distribution 
pipelines that directly serve homes, schools, businesses, and other 
natural gas consumers. Significant differences between gas distribution 
pipelines and gas transmission or hazardous liquid pipelines made it 
impractical to apply the existing regulations to distribution 
pipelines. The proposed rule incorporated the same basic principles as 
current integrity management regulations but with a slightly different 
approach to accommodate those differences. PHMSA worked with a number 
of multi-stakeholder groups to help determine the best way to apply 
integrity management principles to distribution pipelines before 
publishing the NPRM. The work and conclusions of the stakeholder groups 
are described in the NPRM.
    As described in the NPRM, the proposal was responsive to 
recommendations from DOT's Inspector General and the National 
Transportation Safety Board. It also proposed to implement a 
requirement in the Pipeline Inspection, Protection, Enforcement and 
Safety Act (PIPES Act) of 2006 that integrity management requirements 
be established for distribution pipelines.
    The proposed rule also included a provision to allow distribution 
pipeline operators to apply for approval from their safety regulators 
to adjust the intervals at which they perform specific safety 
requirements that current regulations require to be performed at 
specified intervals. This provision recognized the basic principle 
underlying integrity management--that operators should identify and 
understand the threats to their pipelines and apply their safety 
resources commensurate with the importance of each threat. Operators 
devote resources to comply with the core pipeline safety regulations. 
These safety resources can be made available for other purposes where a 
low level of risk makes a longer interval acceptable. Applying those 
resources to other safety tasks to address higher risks can result in 
an overall improvement in safety.
    In addition, the proposed rule would have required distribution 
pipeline operators to install excess flow valves (EFV) in certain new 
and replaced residential service lines. This provision also implemented 
a requirement in the 2006 PIPES Act.

[[Page 63907]]

II. Comments on the NPRM

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

General Comments

    Virtually all comment letters supported the proposed rule, with 
notable exceptions for some of its provisions. The vast majority of 
commenters commended PHMSA for the inclusive way in which the 
background for the proposed rule was developed. Most commenters who 
took exception to particular provisions in the proposed rule objected 
to those provisions as being beyond what stakeholder groups had 
suggested.
    The anonymous commenter suggested that the proposed rule is not 
needed and noted that accidents happen. One operator suggested that 
this entire proposal is unnecessary, since existing rules are adequate 
to assure safety. One operator also opposed the proposed rule, noting 
that system differences mean that the concepts used on transmission 
lines do not apply to distribution and suggesting that the burden of 
implementing integrity management for distribution pipelines would 
cause more harm than good. One state pipeline safety regulatory agency 
also opposed the proposed rule, noting that the existing body of 
regulations has resulted in a very low number of deaths annually from 
distribution pipeline accidents and suggesting that the new 
requirements would therefore not be cost-beneficial. The State agency 
also noted that the new rule will impose additional work on already-
burdened State pipeline safety regulators.
    PHMSA has considered these comments but still considers it 
necessary to issue a rule requiring integrity management for 
distribution pipelines. While accidents may continue to occur, that 
does not mean that reasonable actions should not be taken to avoid 
those accidents that could be prevented. PHMSA concludes that the 
flexibility inherent in the rule, as modified in response to other 
comments (described below), adequately addresses concerns based on 
differences among distribution pipelines. PHMSA also concludes that the 
changes made in response to other comments will reduce implementation 
costs and that the rule will be cost-beneficial. PHMSA is working with 
State pipeline safety agencies to increase the level of Federal 
financial support provided for State programs. PHMSA notes that the 
vast majority of distribution pipeline operators and State regulators, 
and the associations that represent them, supported the proposed rule. 
The existing rules help assure an admirable safety level. Still, 
significant accidents continue to occur, if infrequently. Experience 
has shown that incidents are most often caused by a combination of 
circumstances. These circumstances represent risks for the pipeline 
involved, but may not affect other pipelines. It is thus not practical 
to create additional prescriptive requirements to address these 
pipeline-specific risks. This rule (as the integrity management 
requirements for other types of pipelines that preceded it) requires 
that operators evaluate their pipelines to identify the risks important 
to their circumstances and take appropriate actions to address those 
risks.
    This IM regulation for distribution operators requires an operator 
to conduct a comprehensive evaluation of its system to better identify 
threats to the system, to implement additional measures to help prevent 
accidents from occurring and to mitigate the consequences if an 
accident does occur. IM provides for a more systematic and 
comprehensive approach to preventing failures. Accordingly, PHMSA 
considers this the most effective means to effect further reductions in 
the number of pipeline incidents. The regulatory analysis supporting 
this rule considers the improvement in safety that is expected to 
result and explicitly recognizes the current low frequency of serious 
accidents.

Specific Comments

    There was a broad consensus among commenters that several 
provisions in the proposed rule should be deleted or significantly 
modified. In most cases, the consensus included parties from 
``commercial'' and municipal operators (and their associations) and 
State regulators. Many additional comments were made, often suggesting 
specific changes needed to improve the proposed rule or to make clear 
the actions required to comply. These comment topics are:

Comment Topic 1 Plastic Pipe Reporting.
Comment Topic 2 Performance Through People.
Comment Topic 3 ``Damage'' Definition.
Comment Topic 4 Implementation Time.
Comment Topic 5 Rule Structure and Implementation.
Comment Topic 6 Alternative Intervals.
Comment Topic 7 IM Requirements for Master Meter and LPG Operators.
Comment Topic 8 Transmission Lines Operated by Distribution 
Operators.
Comment Topic 9 Part 192--Requirement References.
Comment Topic 10 Hazardous Leak Definition.
Comment Topic 11 Required Documentation.
Comment Topic 12 Excess flow valves.
Comment Topic 13 Guidance.
Comment Topic 14 Leak monitoring.
Comment Topic 15 State authority.
Comment Topic 16 IM program evaluation and improvement.
Comment Topic 17 Permanent marking of plastic pipe.
Comment Topic 18 Continuing surveillance.
Comment Topic 19 Information gathering.
Comment Topic 20 Knowledge of pipeline.
Comment Topic 21 Threat identification.
Comment Topic 22 Risk assessments.
Comment Topic 23 Performance measures.
Comment Topic 24 Regulatory analysis.
Comment Topic 25 IM for new pipelines.
Comment Topic 26 Annual report form.

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

[[Page 63908]]

not available to the entire industry is unjustified. These commenters 
noted that PPDC issues summary reports, that trade associations (who 
participate in PPDC) provide information to their members, and that 
PHMSA has issued advisory bulletins concerning significant PPDC 
conclusions. Many operators commented that they would not have the time 
or resources to review detailed failure information on their own, and 
that the information currently provided by the trade associations and 
PHMSA advisories is useful to them.
    Some commenters suggested that the rule require operators to make 
use of this information. AGA and one operator suggested that the 
requirement to report plastic pipe failures be replaced with a 
requirement that operators consider industry and government advisories 
in evaluating plastic pipe performance as part of their DIMP programs. 
They believe this would be more effective in addressing PHMSA's 
underlying concern of operators not considering relevant information 
than would mandatory reporting. All who addressed this subject agreed 
that replacing the current system with mandatory reporting of all 
failures would be unreasonably burdensome and would not improve 
knowledge or safety. PPDC commented that mandatory reporting is not 
needed as they have the necessary structure and participation. PPDC 
suggested that it would take years to collect enough data to duplicate 
the information they already have on hand.
    PHMSA response: PHMSA is persuaded that the data collection burden 
is not warranted at this time given the current system of PPDC analysis 
of plastic pipe failure trends and dissemination of lessons learned 
from this analysis via PPDC reports and trade association 
communications and through our advisories. The final rule does not 
include the requirement to report all plastic pipe failures.
    The proposed requirement included reporting failures of couplings 
used with plastic pipe. PHMSA has retained this requirement for 
compression couplings. This final rule includes a requirement that 
operators report failures of compression coupling as part of their 
annual reports. This provision was an included part of proposed Sec.  
192.1009, which would have required reporting of ``each material 
failure of plastic pipe (including fittings, couplings, valves and 
joints)'' (emphasis added). As described above, PHMSA has deleted from 
the final rule the requirement to report plastic pipe failures, since 
it was persuaded by the public comments that PPDC is adequately 
collecting and analyzing this data and disseminating the results of its 
analysis broadly. PPDC does not, however, collect data on couplings 
used to join plastic pipe, since the body of most couplings is metal. 
Coupling failure has been the cause of a number of incidents on 
distribution pipelines in recent years and the subject of several PHMSA 
advisories. Additional data concerning coupling failures is needed to 
enable PHMSA to determine if additional requirements are needed to help 
prevent future incidents from coupling failure. Accordingly, PHMSA has 
retained the included element of reporting of coupling failures in this 
final rule.
    The final rule provision is not limited to couplings used on 
plastic pipe. PHMSA understands that the principal use for couplings in 
distribution pipeline systems is to connect plastic pipe or to connect 
plastic pipe to metal pipe (including risers, etc.). PHMSA recognizes 
that it is possible for mechanical couplings to be used to connect 
metal pipe to metal pipe, and that reporting of failures involving such 
connections would not have been encompassed by the proposed 
requirements related to plastic pipe in the NPRM. PHMSA believes that 
use of couplings in applications that do not involve plastic pipe is 
rare. Nevertheless, PHMSA invites public comment on the extension of 
this proposed requirement to include reporting of failure of couplings 
used in metal pipe. Comments should be submitted by January 4, 2010. 
Based on the comments we receive, we will consider modifying the 
provision. At the end of the comment period, we will either issue a 
modification or a notice stating that the section stands as written.
    An operator is not required to collect coupling failure information 
until January 1, 2010. We expect to issue any modifications to this 
section prior to that date. If we are delayed in issuing a 
modification, we will then consider further delaying the compliance 
date for section 192.1009. PHMSA is issuing, in conjunction with this 
final rule, a 60-day notice regarding amendments to the Annual Report 
form, which includes changes related to this reporting requirement. 
Until PHMSA announces a modification, operators should plan to report 
the information described in the 60-day notice.
    Comment Topic 2: Performance through people.
    Commenters opposed the performance through people (PTP) element and 
the proposed requirement that each IM plan include a section entitled 
``Assuring Individual Performance.'' Commenters maintained that the 
proposed requirement is vague and likely unenforceable and that it 
creates confusion and diminishes the focus on the core issues of 
importance to IM. They pointed out, as did PHMSA in the NPRM's 
preamble, that other regulations currently address the impact of people 
on pipeline safety. These regulations include Operator Qualification, 
Drug and Alcohol requirements, Damage Prevention, and Public Awareness. 
Commenters noted that the proposed PTP requirement is unclear about 
what, if any, additional actions are expected, and that having to refer 
to actions taken under these other requirements in an IM plan creates 
an unnecessary additional paperwork burden. NAPSR, American Public Gas 
Association (APGA), GPTC, and operators suggested that PHMSA should not 
presume that action is required by all operators to address the threat 
of inappropriate operation. These commenters noted that studies, 
including those conducted by the American Gas Foundation (AGF) and 
Allegro and referred to in the preamble of the NPRM, have shown that 
this threat poses a very small risk; PHMSA data shows it to be the 
cause of only 3% of all leaks.
    PHMSA response: PHMSA has not included PTP requirements in the 
final rule. PHMSA agrees the provision is largely duplicative of other 
existing regulations. Nevertheless, the final rule still requires that 
operators evaluate all threats applicable to their pipeline systems. 
Thus, operators for which inappropriate operation is a threat of 
concern will be required to address that threat.
    Comment Topic 3: ``Damage'' definition.
    In the NPRM, PHMSA proposed to add a new definition for ``damage'' 
applicable to the IM subpart. The proposed definition was ``any impact 
or exposure resulting in the repair or replacement of an underground 
facility, related appurtenance, or materials supporting the pipeline.'' 
This term is being defined because of a provision in the proposed rule 
that would require reporting the number of excavation ``damages'' as a 
performance measure. Industry stakeholders universally commented that 
the definition of ``damage'' should be limited to excavation damage and 
to damage that causes loss of gas (immediate leaks). GPTC would further 
limit the definition to ``known'' excavation damage. States and NAPSR 
suggested defining excavation damage vs. damage, but did not suggest 
limiting damage of interest to damage causing leaks. One operator

[[Page 63909]]

suggested that the definition should also include instances in which 
damaged pipe is retired in place because damaged pipe and appurtenances 
are not always repaired or removed; the operator suggested that the 
definition should focus on the unplanned nature of the repair, removal 
or retirement.
    The commenters pointed out that operators report data regarding 
leaks in their annual reports but not other damage. Operators are not 
now required to collect data on damages that do not result in leaks. 
Commenters contended that extending the definition of damage to 
encompass situations that do not cause leaks will cause loss of 
continuity with previous data and may cause confusion. Some noted that 
statistically better conclusions can be drawn if such continuity is 
maintained. Some commenters asked whether coating damage or damage to 
anodes/test wires would be included. Others noted that discovery of 
latent damage, that may have occurred years earlier, is not a measure 
of the current effectiveness of a damage prevention or integrity 
management program. Industry expressed concern about the additional 
recordkeeping burden associated with capturing data on non-leak 
damages.
    Two operators suggested that the term ``exposure'' be eliminated 
from the proposed definition of damage (or excavation damage) because 
it is unclear what this term adds. They question, for example, whether 
washouts would be included.
    PHMSA response: PHMSA agrees that excavation damage is of principal 
concern and is the term that should be defined. PHMSA does not agree, 
however, that only excavation damage that results in a leak is of 
concern.
    Mitigating the threat of excavation damage means implementing or 
continuing actions that will minimize the likelihood that excavation 
near the pipeline will cause damage. Operators must seek to prevent 
excavation ``hits'' of the pipeline, whether a hit results in leakage 
or not (e.g., a glancing blow or insufficient force to cause a leak). 
That a hit occurs, regardless of whether it causes leakage, is an 
indication that the actions intended to prevent such an occurrence have 
failed. Operators cannot adequately evaluate the effectiveness of their 
mitigative actions for this threat, and PHMSA cannot evaluate the 
effectiveness of these actions on a national level, if non-leak events 
are excluded. Assuring continuity with past data is less important than 
assuring that the data being collected appropriately addresses the 
event of concern.
    At the same time, PHMSA is sympathetic to the need to have well-
defined criteria identifying what damage is to be included in 
performance monitoring and understands that a definition based on 
whether a leak occurred would provide clarity; however, it would not 
allow operators and PHMSA to monitor the effectiveness of damage 
prevention measures.
    Pipeline operators, as well as operators of all underground 
facilities, need to evaluate the effectiveness of damage prevention 
efforts. The Common Ground Alliance (CGA) is a national group involving 
operators of all types of underground facilities, as well as 
representatives of excavators and others who play a part in preventing 
damage to underground facilities. CGA has established the Damage 
Information Reporting Tool (DIRT) to collect information submitted 
voluntarily concerning damage to underground facilities. Some pipeline 
operators participate in DIRT. DIRT defines damage based on whether 
repair or replacement of an underground facility is required. This is 
very similar to the definition proposed in the NPRM, which also relied 
on the need to repair or replace as the defining criterion. PHMSA has 
modified the definition in the final rule to match more closely the 
language used in the DIRT definition of excavation damage. PHMSA has 
omitted the phrase ``of exposure'' used in the DIRT definition, since 
this refers to damage from causes other than excavation (e.g., 
washout). The changes in the definition in the final rule will provide 
the needed clarity and will also facilitate potential comparison of 
distribution pipeline damage prevention performance to that of other 
underground facilities for which CGA collects data. This change also 
obviates the need to include retirement in the definition because 
retirement of an active pipeline will usually involve replacement or 
bypass. Damage to the protective coating or to the cathodic protection 
that requires repair/replacement is damage of concern in evaluating the 
effectiveness of damage prevention measures; therefore, the definition 
in the final rule clarifies that damage necessitating repair to coating 
or to cathodic protection constitutes excavation damage.
    Comment Topic 4: Implementation time.
    Many industry commenters objected to the requirement that IM plans 
be ``fully implemented'' within 18 months. They suggested that 
``fully'' be deleted. IM plans inherently involve learning more about 
the pipeline systems and associated risks, and it is not clear when 
they will be ``fully'' implemented.
    A few operators suggested we clarify what is meant by 
``implement.'' They noted that it was not clear if this meant that all 
databases must be fully populated and that, if so, it cannot be 
accomplished in 18 months. Many industry commenters also objected to 
the proposed requirement that implementation occur within 18 months. 
They argued that many operators will need to make changes in how they 
collect and manage data, including the need to purchase new computers 
and develop new databases or make other IT changes, and that these 
changes take time. Industry also suggested that it is not practical to 
expect that plans will be implemented, databases will be fully 
populated, etc., for all portions of complex distribution systems in a 
short period of time. AGA noted that Congress allowed 10 years for full 
implementation of gas transmission IM. Commenters varied in their 
suggestions for a different implementation deadline. Many suggested 24 
months, with one operator clarifying that after such a period operators 
should be required to have developed and implemented a ``framework'' 
that will further develop over time. One operator suggested one year to 
develop plans/programs and another year to implement. Others suggested 
variations on this approach, with 1\1/2\ years allowed either for 
development or implementation.
    One operator commented that the proposed rule was too ambiguous as 
to the actions required to implement its provisions. It stated that the 
rule lacks the clarity needed to know what must be done.
    PHMSA response: PHMSA has deleted the term ``fully'' from the final 
rule. PHMSA has retained the 18-month requirement. PHMSA recognizes 
that implementing IM plans involves learning and revision but does not 
agree that this means it is necessary to stretch out the implementation 
deadline. It is important to implement--to begin the iterative learning 
process--as soon as practical. With ``fully'' being deleted, as noted 
above, it is clear that implementation is not expected to mean that all 
problems have been identified and resolved. PHMSA notes that 18 months 
is consistent with the period suggested by many commenters for 
developing IM programs and, with deletion of the concept of ``fully 
implement,'' believes this period is still appropriate.
    AGA's comment is incorrect. Congress allowed 10 years for gas 
transmission operators to complete baseline

[[Page 63910]]

assessments (i.e., physical inspection) of the portions of their 
pipelines in high consequence areas.\1\ The proposed rule did not 
include a provision for distribution pipeline operators to conduct such 
assessments. Transmission pipeline operators were required to develop 
and implement IM plans in one year.\2\
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    \1\ Pipeline Safety Improvement Act of 2002, Section 14.
    \2\ 49 Code of Federal Regulations, Section 192.907.
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    PHMSA disagrees with the comment that the rule is ambiguous. This 
comment was not echoed by the many other operators or the trade 
associations that submitted comments. Some commenters identified 
specific areas where they believed further clarity was needed and PHMSA 
has made changes where appropriate, as described below. As a result, 
PHMSA concludes that the actions required to implement the final rule 
are clear.
    Comment Topic 5: Rule structure and implementation.
    Several commenters addressed specific issues associated with the 
structure of the rule and language in proposed Sec.  192.1005 
addressing what gas distribution operators must do to implement this 
new subpart. A consultant and GPTC both suggested that section headers 
within the rule not be written as questions because questions are 
inherently longer than classic titles, and make the rule harder to use.
    AGA and several distribution operators objected to the proposed 
requirement that procedures describe the ``processes'' for developing, 
implementing and periodically improving IM elements. The Iowa Utilities 
Board (Iowa) also suggested that this provision be modified to remove 
the reference to processes. The commenters noted that the term is 
unclear and could be interpreted to require elaborate algorithms. They 
noted that the stakeholders concluded that major technical changes are 
not needed, which they interpret to mean that major ``processes'' are 
not required to implement distribution IM. They believe that deleting 
the term does not affect the meaning of the proposed requirement.
    PHMSA response: The structure of the regulation as question and 
answer is part of the long-standing Government-wide requirement to 
write regulations in ``plain English.'' PHMSA has been consistently 
using this format in its pipeline rulemakings for some time. PHMSA has 
revised Sec.  192.1005(b) to delete the reference to ``processes.''
    Comment Topic 6: Alternative intervals.
    Commenters generally favored the proposed requirement that would 
allow operators to propose alternative intervals for part 192 
requirements. There were a number of comments related to this provision 
and its implementation.
    a. Concept.
    AGA, GPTC, and many gas distribution operators supported the 
proposal. They noted that shifting of resources often is necessary to 
assure safety efficiently. They believe that the proposed rule would 
not be cost-beneficial unless it allowed for such adjustments. They 
noted that risk-based intervals are more effective and efficient and 
can result in improved safety and reduced costs. In response to a 
preamble question concerning advantages and disadvantages of allowing 
operators to adjust required intervals, some operators commented that 
the engineering work needed to establish new intervals and the need for 
State review and understanding of the basis were disadvantages of 
PHMSA's proposal.
    PHMSA response: This provision is intended to facilitate 
realignment of safety resources, where appropriate, to promote 
efficiency without compromising safety. Because operators are in the 
best position to understand the risks on their system, and where 
resources should be effectively applied, this provision is designed to 
give operators that latitude to effectively manage their systems. 
Approval from regulators is necessary to prevent the abuse of this 
provision. Operators are not required to apply for adjusted intervals. 
If the burden of engineering work and seeking State review are too 
burdensome, the operator may continue to use the intervals in the 
regulations.
    b. Process.
    AGA, GPTC, and several operators suggested that it will be 
important for PHMSA to provide guidance to the States for implementing 
alternative intervals. One operator suggested a federal ``template'' to 
be used by the States. Commenters suggested that consistency would be 
particularly important for large companies that operate pipelines in 
multiple states. One commenter stated the process should be 
``streamlined.'' NAPSR, however, asserted that approval should be per 
State procedures, with flexibility provided for each State to consider 
its particular circumstances. Iowa also noted that such guidance is not 
needed.
    The Massachusetts Department of Public Utilities suggested that a 
process needs to be defined for appeal of decisions related to 
proposals for alternative intervals. They believe that such a process 
should be consistent with that for waivers under 49 U.S.C. 60118.
    PHMSA response: State authority and regulatory structures differ, 
and some state regulators may need to seek additional authority (from 
their state government) to implement this provision. States will 
implement this provision under individual state statutory authority in 
accordance with the applicable certification under 49 U.S.C. 60105 of 
this title or agreement under section 60106. PHMSA believes most states 
will be able to establish procedures under existing authority and may 
already have procedures that can be used for this purpose.
    PHMSA agrees with NAPSR that states need flexibility in 
implementing this provision. PHMSA will develop criteria for evaluating 
operator's alternative interval proposal in the states where PHMSA 
exercises enforcement authority over distribution pipelines. States may 
be able to use those criteria where they exercise enforcement 
authority. Factors important to each regulatory authority's 
consideration of proposed changes to intervals for safety actions are 
also likely to differ. These differences make it impractical to develop 
a common ``template'' process.
    PHMSA agrees that the regulatory authority responsible for 
reviewing the request should institute appropriate administrative 
procedures for processing requests for alternative intervals, to 
include a process for appealing a decision. States will establish their 
own procedures for review, and it is not appropriate for PHMSA to 
impose a ``streamlined'' process on state actions.
    c. Approving agency.
    NAPSR, States, and some industry commenters suggested that the rule 
be clarified that approval must be requested from the regulatory 
authority exercising jurisdiction. They considered the language in the 
proposed rule vague as to whether a state or PHMSA was the approving 
agency, or whether an operator could apply to either. One operator 
suggested that approval should be by States.
    PHMSA response: PHMSA has always intended that the alternative 
interval provision in this rule would allow the regulatory authority 
exercising jurisdiction over the operator of the distribution pipeline 
to act on a proposal to use alternative intervals. We have clarified 
the language in the final rule to remove any implication that an 
operator may seek approval from either

[[Page 63911]]

PHMSA or a state. Most distribution pipelines are regulated by state 
agencies and approval of changes proposed by those operators will be by 
the state.
    d. Evaluation of proposals.
    A number of commenters addressed the proposed requirement that 
operators proposing alternative intervals demonstrate that a reduced 
frequency will not significantly increase risk. NAPSR proposed that 
operators should be required to demonstrate enhanced system safety or, 
at minimum, that operation would be at least as safe under the proposed 
alternative. Iowa suggested a requirement for a substantially equal or 
superior level of safety. One operator requested that the meaning of a 
significant increase in risk be clarified by example, noting that the 
proposed language is unclear. Another suggested that the rule should 
not require a proposal for an alternative interval to include a no-
significant-risk demonstration; the commenter noted that the core 
pipeline safety regulations are not risk based and suggested that risk 
must be considered on an overall basis vs. change-by-change.
    Although commenters generally supported consistency between 
regulatory authorities, commenters also suggested that there is no 
single basis for judging the adequacy of the engineering basis for a 
proposed change, and that it is not practical or necessary to define 
requirements for performance/data analysis. One operator suggested that 
engineering analyses should be judged on whether they are performed by 
an engineer, are subject to internal review, use good data, and include 
logical analyses and conclusions. GPTC and one operator suggested that 
no additional analysis should be required if performance measures show 
that risk mitigation is effective.
    AGA and several commenters noted that there should be no arbitrary 
limit on the change in interval that will be allowed.
    PHMSA response: The rule does not require and PHMSA does not 
contemplate that operators will produce a precise quantitative estimate 
of risk. Accordingly, PHMSA recognizes that it is not easy to 
demonstrate that any action produces no significant increase in risk. 
However, regulating safety requires judgments weighing risk versus 
costs. Judgments of this type are what operators will need to support 
their proposals and regulators will need to consider. PHMSA does not 
agree that any reduction in safety intervals is unacceptable because 
the change alone would result in some increase in risk. Instead, the 
regulatory authority needs to make an overall judgment on the adequacy 
of proposed changes.
    PHMSA has revised the final rule to require that alternatives, as 
part of the overall IM plan, provide an equal or improved overall level 
of safety. This change is intended to eliminate any implication that a 
quantitative estimate of risk is required. PHMSA expects that operators 
will be conscientious in demonstrating that proposals produce a level 
of safety that is equal or improved, on an overall basis, and that 
states will be reasonable in judging the adequacy of proposed changes.
    PHMSA also agrees that it is unnecessary and likely impractical to 
establish specific criteria for approval of proposals for alternative 
intervals. Each proposal must be considered as a whole and on its own 
merits. PHMSA has not adopted any of the various alternatives suggested 
by commenters because each regulatory authority must exercise its 
judgment based on the circumstances of each request. However, PHMSA 
also recognizes the industry's need for some degree of consistency in 
how proposals are evaluated. PHMSA intends to work with the states to 
help assure a degree of consistency.
    PHMSA is not specifying any limit on the intervals that may be 
authorized by the regulatory authority. The regulatory authority will 
be responsible for determining safe intervals based on the information 
in each operator's proposal.
    e. Opposition.
    The Florida Public Service Commission opposed the proposal to allow 
alternative intervals. The Commission maintained that waivers (their 
characterization) inherently reduce the established minimum safety 
level. They believe that processing these proposals will be burdensome 
and that proposed waivers would generally not be approved. If the 
provision is retained, they suggest that the risk analysis used as a 
basis for changes must be transparent to the regulator. They also 
suggest that the code be revised to require that operations and 
maintenance (O&M) plans be required to contain a summary of maintenance 
tasks and approved periodicity, since it will no longer be possible to 
use a common inspection template if operators are not required to 
conduct actions at the same intervals.
    PHMSA response: Waivers from regulatory requirements (sometimes 
also called special permits) are a common regulatory tool. PHMSA 
permits pipeline operators to seek a special permit \3\ and considers 
such requests on their merits. Although required periodic actions 
address threats of concern and a reduction in the periodicity of those 
actions inherently involves an increase in risk, adjustments to the 
frequency may be warranted when safety resources are applied to other 
areas of greater concern. Contrary to the assertion of the commenter, 
the use of waivers can result in a reduction in overall risk (i.e., 
improvement in safety), and regulators must make judgments regarding 
the overall effect of proposed changes.
---------------------------------------------------------------------------

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

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

[[Page 63912]]

not apply. PHMSA therefore sees no need to revise the rule language to 
recognize that such situations may exist.
    Operators apply safety resources to purposes other than 
inspections/actions required periodically by regulation. Operators will 
be able to realign those resources without regulatory approval, based 
on insights that their risk analyses may supply, providing a means by 
which they can make their safety activities more efficient, thereby 
permitting them to avoid increased costs.
    g. An industry consultant suggested that the current requirement to 
inspect inside meter sets for atmospheric corrosion at 3-year intervals 
should be changed. He noted that experience shows these inspections are 
not needed and it is more efficient to change the requirement on a 
national basis.
    PHMSA response: This is an example of a required periodic 
inspection where an operator could propose a modification if its 
analysis showed devoting resources in another area would be more 
beneficial from a safety standpoint. Changing this periodic requirement 
on a national basis is outside the scope of this rulemaking.
    h. Some operators suggested that implementation of alternative 
intervals should be allowed, based on risk analysis, without requiring 
regulatory approval. They noted that reductions in effort, where found 
appropriate, are an integral part of implementing a risk-based 
approach. They expressed concern that state regulators will be 
unwilling to approve reductions from established intervals which, 
although not risk-based, are an accepted norm.
    PHMSA response: PHMSA does not think regulatory approval should be 
eliminated. Regulatory oversight is appropriate for changes that 
involve reducing safety actions currently required by regulation. PHMSA 
recognizes that there may be some reluctance to approve reductions from 
an established norm; however, PHMSA plans to assist states to determine 
appropriate methods to evaluate proposals. PHMSA believes that these 
efforts will serve to address any reluctance on the part of state 
regulators to consider alternative intervals.
    Comment Topic 7: IM requirements for master meter and LPG 
operators.
    Many comments addressed the proposed limitation of requirements for 
master meter and LPG operators (MM/LPG) and PHMSA's request for comment 
on these limitations. PHMSA asked whether the proposed limitations were 
appropriate, whether further limitations were needed or if these 
operators should be exempt from IM requirements. PHMSA also asked 
whether similar limitations should be afforded to other types of 
operators.
    a. Proposed limitations are inappropriate.
    Two major trade associations addressed the proposed limitations for 
master meter and LPG operators. (Neither group's members include 
operators of this size.) AGA suggested that these smaller operators 
should be required to implement distribution IM, but that the 
requirements should be scalable, recognizing the uncomplicated nature 
of their facilities.
    APGA agreed that MM/LPG should not be excluded from IM 
requirements. They noted that if mandatory reporting of plastic pipe 
damages is eliminated (as they suggested) the limitation essentially 
becomes an exclusion from filing annual reports. Master meter operators 
are currently excluded from annual report requirements. APGA ``would 
not object'' to adding a requirement that master meter and LPG 
operators evaluate and prioritize risk. APGA sees risk ranking as an 
integral part of assessing risks, and believes it will occur whether or 
not it is required explicitly in the rule.
    NAPSR, Connecticut Department of Public Utility Control, 
Pennsylvania Public Utility Commission (PPUC), and several operators 
also commented that MM/LPG should be subject to IM requirements. They 
referenced the conclusion of the stakeholder groups that distribution 
IM should apply to all distribution operators. These commenters did not 
agree that these operators pose less risk, and maintained that simpler 
systems will inherently have simpler programs. They also noted that 
some master meter operators are much larger than the NPRM stated. PPUC 
explained that there are two master meter operators in its state with 
more than 6,000 customers. Other commenters noted that there is limited 
data on these systems, since they do not report incidents, and thus the 
risk may not be small.
    The Arizona Corporation Commission (AZCC) commented that all LPG 
operators should not be treated like master meters, since some serve 
small towns, like local distribution companies and have the same 
limited control over the principal threat of excavation. AZCC suggested 
that LPG operators who serve a city, town, or other municipality within 
a specified service area as defined by the state agency with authority 
should meet the same requirements as other distribution system 
operators. AGA and NAPSR noted that LPG poses unique risks because the 
product is heavier than air, unlike natural gas. Leaks from these 
systems will not safely disperse, as will leaks from natural gas 
distribution systems.
    PHMSA response: PHMSA is persuaded that there is a reasonable 
criterion to distinguish between LPG operators. PHMSA's concern with 
overwhelming small operators with limited resources and technical 
expertise is not applicable to LPG systems serving hundreds or 
thousands of customers because those operations are more like small 
natural gas distribution system operators. PHMSA notes that existing 
regulations include a criterion to differentiate between large and 
small LPG operators. Section 191.11 excludes LPG operators serving 
fewer than 100 customers from a single source from filing annual 
reports. Other LPG operators are required to file such reports. PHMSA 
has revised the final rule to embrace this same criterion. LPG 
operators serving fewer than 100 customers from a single source are 
treated like master meter operators. Other LPG operators must meet the 
same requirements as natural gas distribution pipeline operators.
    We are also persuaded that MM/small LPG operators should not be 
exempt from ranking risks--a requirement we had applied to all other 
distribution operators in the proposed rule. We believe that these 
operators will gain a better understanding of their systems by going 
through the ranking process. Ranking the risks is almost inherent in 
the other requirements and should not impose an additional burden on 
these operators. PHMSA has added an element to rank risks to the 
requirements applicable to MM/LPG systems.
    b. MM/LPG should be subject to limited IM requirements.
    The Indiana Utility Regulatory Commission does not agree that MM/
LPG should be subject to the same requirements as other operators. 
Indiana commented that although there are reasons that master meter 
operators could be perceived as posing higher risk (e.g., lack of 
expertise/resources, distributing gas is not primary business, high 
population density), there has been no record of serious incidents at 
master meters in Indiana. They stated that these operators struggle to 
comply with existing rules and will have limited ability to analyze 
risks, even if the computer program APGA is developing (Simple, Handy, 
Risk-based, Integrity Management Program--SHRIMP) is available. Indiana 
suggested we should either exclude master meter operators from this 
rule or subject them to more limited requirements and allow them to

[[Page 63913]]

spend their limited resources achieving compliance with existing 
regulations.
    While not supporting total exclusion, Missouri and New Hampshire 
state regulators supported limited requirements for MM/LPG. AZCC 
commented that the rule should be prescriptive and simple for master 
meter and small LPG operators, since these operators have limited 
capability, can be easily overwhelmed and may, if that happens, do 
nothing. The New Mexico Public Regulation Commission (NMPRC) supported 
excluding MM/LPG from administrative requirements of the proposed rule.
    Iowa did not take a position on limiting requirements; however, 
Iowa and a large operator suggested that evaluation and prioritization 
of risks should not be excluded for MM/LPG. They see this as a critical 
step, and not particularly burdensome.
    PHMSA response: While PHMSA agrees that there are some ``large'' MM 
operators, most of them are very small. Unlike the large/small LPG 
operator distinction, which exists in current regulations, all MM 
operators are treated the same, irrespective of size. Therefore, in 
this final rule, all MM are subject to the limited IM requirements.
    The final rule imposes requirements similar to those for other 
operators but with more limited requirements for documentation, 
consistent with how these operators are treated in other regulations. 
They will not be required to report performance measures as they do not 
file annual reports.\4\ Although these requirements are similar to 
those applicable to other operators, we have presented them separately, 
emphasizing that these programs should reflect the simplicity of the 
pipelines.
---------------------------------------------------------------------------

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

    Some comments in response to the NPRM and comments made during 
earlier stakeholder discussions have disagreed with PHMSA's contention 
that MM/LPG operators pose less risk. Risk is generally considered to 
be the product of the likelihood of adverse events and their 
consequences. Determining risk thus requires knowledge of how often 
events occur and the consequences they produce. MM/LPG operators are 
not required to submit written incident reports. They are, however, 
required to make telephonic reports.\5\ Events with serious 
consequences (e.g., death or serious injury) are also likely to be 
reported in local news and thus to come to the attention of regulatory 
authorities. PHMSA therefore believes it is unlikely a large number of 
significant events have occurred on MM/LPG systems that are not 
reflected in incident data. That data includes few serious incidents on 
MM/LPG systems, supporting PHMSA's contention that the risk from these 
systems, while not zero, is relatively low. Indiana's comments about 
the dearth of serious accidents in the incident record are consistent 
with PHMSA's understanding of the risk of these systems.
---------------------------------------------------------------------------

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

    c. MM/LPG should not be subject to IM requirements.
    The National Propane Gas Association (NPGA) suggested that LPG 
operators should be exempt entirely. NPGA sees no perceived benefit 
from compliance with the proposed requirements. They noted that LPG 
systems are very small, that they generally include pipe runs measured 
in feet vs. miles, and that the total quantity of gas that could be 
released in an accident is limited by the capacity of the supply tanks, 
a limitation not shared with natural gas systems. NPGA maintained that 
their members are already sufficiently regulated, mostly by states and 
through the incorporation of NFPA Standard 58 (NFPA-58) into Part 192 
by reference. They believe that NFPA-58 mirrors the requirements of 
Part 192 and the proposed rule and noted that the standard is already 
recognized as the primary governing standard in Sec.  192.11(c) which 
states that the standard prevails in the event of a conflict between 
its provisions and Part 192. NPGA also suggested that applying this 
rule to LPG operators could have unintended consequences. In a 
competitive environment to reduce costs, operators could break up their 
systems to fall outside of regulation, thus removing safety oversight 
completely.
    PHMSA response: In the NPRM we proposed a simpler set of IM 
requirements for MM/LPG operators, but we asked if these operators 
should be completely excluded from IM requirements. The bulk of 
comments supported limited requirements but opposed excluding these 
operators, arguing that simple pipelines would need only simple IM 
plans. In the final rule, PHMSA has not excluded these operators.
    LPG presents unique hazards; accordingly, PHMSA believes pipeline 
safety will be enhanced by larger LPG operators engaging in more robust 
integrity management activities. As discussed above, large LPG 
operators are subject to the full IM requirements in the final rule, 
including the administrative requirements. Because of the physical 
nature of LPG and the safety risks it presents, PHMSA is not persuaded 
that small LPG operators should be exempted. Furthermore, NFPA Standard 
58 does not ``mirror'' the integrity management requirements in this 
rule and does not adequately address the safety measures provided by 
this final rule. IM requirements will complement NFPA-58.
    d. Limitations for small gas distribution operators (other than MM/
LPG).
    A consultant suggested that distribution IM should be limited to 
large operators at this time. He noted that the PIPES Act does not 
mandate such requirements for small operators and suggested that a 
phased approach would be prudent. He believes that small operators do 
not have the personnel or background to implement these requirements 
and that the associated costs will likely exceed the benefits. He noted 
that the risk from third-party damage on such systems is small, as 
operators' personnel see most of the system daily. He supported 
exclusion for small operators similar to that proposed for MM/LPG and 
suggested that PHMSA collect additional data to see if additional 
requirements are needed for these operators. A large operator also 
supported limited requirements for small operators, and would include 
the number of customers or mileage as a threshold criterion.
    The Washington Citizens Committee on Pipeline Safety commented that 
the number of services should not be used alone to delineate small 
systems. They suggested that the type and uniformity of material, 
system complexity, geographic spread, and other risk factors be 
considered as well.
    APGA suggested that criteria defining a small system should not 
include limitation to one pressure district and should not limit the 
type of appurtenances or equipment. APGA commented that these 
differences do not affect risk. Small distribution operators already 
file annual reports, so APGA believes that extending the proposed 
limitations for MM/LPG would have no value for other small operators.
    NMPRC would exclude small operators from the administrative 
requirements of the proposed rule based on the number of customers or 
staff. NMPRC concluded that DIMP principles would be beneficial for 
these operators but that the associated administrative burden is too 
great.
    Missouri would extend all of the MM/LPG limited requirements to 
small operators.
    PHMSA response: PHMSA has not limited this rule to large operators. 
As

[[Page 63914]]

noted in the NPRM, there is no established threshold to distinguish 
between large and small operators. In addition, the PIPES Act did not 
differentiate between large and small distribution operators. The PIPES 
Act requires, ``the Secretary shall prescribe minimum standards for 
integrity management programs for distribution pipelines.'' \6\ We 
received few comments regarding how such a threshold might be 
established.
---------------------------------------------------------------------------

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

    Rather than delineating explicit thresholds based on operator size, 
PHMSA expects that operators with small systems will need only 
simplified plans. Operators will be able to scale their programs 
according to the complexity of their distribution systems. For example, 
APGA's SHRIMP program will be available to assist small operators in 
developing their IM plans.
    e. Limitations for other operators.
    One operator suggested that limited requirements should also be 
established for ``circumstantial'' or ``incidental'' operators. This 
operator is a large company operating hazardous liquid pipelines, but 
operates a single gas service line from a local distribution company 
main to a flare at a petroleum barge dock. The operator believes it 
would be burdensome to have a distribution IM plan for this single 
service line. A consultant and GPTC also suggested that landfill gas 
operators should be treated like MM/LPG, since their systems are also 
small and pose limited risk.
    New Hampshire recommended that operators of conventional 
distribution systems that also operate LPG should be allowed to use a 
single plan for both. One operator suggested that LDC operators that 
also operate MM/LPG should be allowed to use a single DIMP plan for 
both.
    PHMSA response: As MM/LPG operators have not been excluded from IM 
requirements, we see no compelling reason to exclude these other 
``small'' operators. PHMSA considers that the analysis of a small, 
simple system should be relatively straightforward and should result in 
a basic IM plan. PHMSA notes the commenter operating a single service 
line to a flare stack may be considered a large volume customer as long 
as the service line is not on public property. This final rule does not 
apply to in-plant piping to a large volume customer. Companies that 
conclude that compliance with a rule would be overly burdensome due to 
unique circumstances may have the option to apply for a waiver (or 
special permit), as permitted by the applicable regulatory oversight 
authority.
    The rule does not require that operators of conventional 
distribution systems that also operate LPG have separate IM plans or 
that operators of both MM and LPG systems have separate plans for each. 
We expect that plans developed for their conventional pipelines in 
response to the other requirements of subpart P should also satisfy 
Sec.  192.1015. PHMSA agrees that operators with multiple ``systems'' 
may benefit from having a single IM plan. However, it is also possible 
that operators who own multiple systems may operate them separately and 
may desire separate IM plans. Under the final rule, operators will have 
the flexibility to treat multiple systems under a common plan, or to 
address them separately.
    Comment Topic 8: Transmission lines operated by distribution 
operators.
    Many industry commenters suggested that piping operated by 
distribution operators but which is classified as transmission (mostly 
because it operates at greater than 20% SMYS) should be included in a 
distribution IM plan rather than in a separate transmission IM plan. 
These commenters suggested that this could be done in this rule or by 
changing the definition of a transmission line. Commenters explained 
that this ``transmission'' piping is usually operated as an integral 
part of the distribution system, and that it would be more efficient to 
treat it under distribution IM than under a separate transmission IM 
plan. Several commenters recognized that additional rulemaking may be 
needed to accomplish this change.
    PHMSA response: PHMSA has made no change in response to these 
comments. The NPRM did not address changing the definition of 
transmission pipeline; therefore, such an action is outside the scope 
of this rulemaking.
    The transmission IM regulations already provide for alternative 
treatment of low-stress transmission pipeline (<30% SMYS) \7\ in 
recognition that this low-stress pipe is more likely to fail by leakage 
rather than by rupture. PHMSA also notes that stakeholder groups 
studied the appropriateness of treating low-stress transmission 
pipeline under distribution IM programs. The groups reviewed the 
existing research concerning the likely failure mode of low-stress 
transmission pipelines. The record indicated that failure is expected 
to be by leakage when the failure results from corrosion. It is less 
clear that the likely failure mode would be leakage when the failure 
results from prior mechanical damage (e.g., from outside force). The 
stakeholder groups concluded that additional technical work is needed 
to better define the threshold stress level at which the likely failure 
mode transitions from leakage to rupture to determine if low-stress 
transmission pipeline should be addressed under a distribution IM 
program.\8\ PHMSA may consider this change later but agrees with the 
stakeholder conclusion that additional research is required to support 
such a change.
---------------------------------------------------------------------------

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

    Comment Topic 9: Part 192 requirement references.
    NAPSR, APGA, and a number of operators objected to the proposed 
requirement that all operators must enhance their damage prevention 
programs (proposed Sec.  192.1007(d)) because the requirement is open-
ended. They suggested that Sec.  192.614, which requires such programs, 
should be revised if current programs are deemed inadequate.
    A consultant suggested that leak management requirements should be 
included in Sec.  192.723 and damage prevention requirements in Sec.  
192.614. He generalized this comment by noting that PHMSA should avoid 
having two regulations that address the same thing. He considers IM as 
an extension of all of Part 192, and believes that proposed Subpart P 
should be limited to the high-level approach to IM and related 
documentation.
    PHMSA response: The final rule requires that operators have and 
implement leak management programs. Programs to manage known leaks are 
different from periodic leak surveys required by Sec.  192.723.
    Operators are required to implement a damage prevention program 
under Sec.  192.614. After further consideration, PHMSA determined a 
requirement to enhance damage prevention programs on gas distribution 
systems through integrity management was impracticable because these 
programs are largely state-run. PHMSA is persuaded that modifications 
to damage prevention requirements for distribution systems should be 
made through amendments to Sec.  192.614 rather than through this 
rulemaking. PHMSA has eliminated the proposed requirement to enhance 
damage prevention programs as part of an integrity management effort. 
Although all references to the damage prevention requirements in Sec.  
192.614

[[Page 63915]]

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

[[Page 63916]]

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

[[Page 63917]]

standards required for EFV installation, most of these simpler master 
meter and LPG systems will not meet the threshold and operators of 
these systems will install few, if any, EFVs as a result of this 
requirement. For example, many of these systems operate at very low 
pressures, and the rule provides that EFVs need not be installed where 
operating pressure is less than 10 psig.
    f. Terminology.
    One operator suggested that the references to Sec.  192.381 should 
refer to ``performance standards'' rather than to performance 
requirements, as that would be more accurate.
    PHMSA response: PHMSA agrees and has made this change.
    Comment Topic 13: Guidance.
    A number of comments addressed guidance available for implementing 
this rule.
    a. PHMSA guidance.
    AGA and several operators suggested that the guidance document 
prepared by PHMSA, and included in the docket, is not necessary. They 
noted that the GPTC Guidance for integrity management (an appendix to 
the GPTC Guide) is more complete and will be available separately from 
the GPTC Guide, at nominal cost. Iowa commented that PHMSA's guide is 
not useful and that it conflicts with the provisions in the rule 
concerning leak management. One operator suggested that the PHMSA 
guidance document contains adequate detail for master meter and LPG 
operators but that references to requirements for larger operators 
should be eliminated from it. They commented that the document does not 
accurately reflect reporting and other requirements for larger 
operators.
    PHMSA response: PHMSA agrees that the GPTC appendix provides more 
information than PHMSA's draft guidance. PHMSA is concerned, however, 
that the GPTC appendix will not be useful for most master meter and 
small LPG operators. Many of these operators will likely not purchase 
the Guide or the separate appendix. The appendix contains more 
information than these operators need, and they often lack the 
technical resources to extract the more-limited information that is 
important to their operations. PHMSA considers it important to provide 
guidance focused specifically on the needs of MM/LPG operators and will 
edit its guidance document to do so. PHMSA will remove other 
information and defer to the GPTC appendix as guidance for larger 
operators.
    b. GPTC Guide.
    GPTC and an industry consultant noted that the preamble stated 
PHMSA would revise GPTC guidance if needed. They point out that only 
GPTC can change that guidance.
    PHMSA response: The commenters are correct. The statement in the 
NPRM referred to potential changes PHMSA might make to its own guidance 
for MM/LPG operators, not to the GPTC guidance.
    Comment Topic 14: Leak monitoring.
    A large distribution operator suggested that the rule should not 
require operators to ``implement'' leak monitoring because that implies 
they do not now have such programs. They suggested that the rule 
require that operators ``have'' such programs. The operator also 
suggested that the rule delineate the contents of an effective program.
    Several smaller operators suggested that leak monitoring should not 
be required in this rule at all. They commented that only risk measures 
indicated as appropriate by risk analysis should be required.
    APGA noted that some operators do not monitor leaks; they repair 
all leaks. APGA contended that these operators should not be required 
to establish criteria to grade leaks. Operators who do not repair all 
leaks should have criteria for grading leaks not repaired.
    PHMSA response: Leakage is the principal failure mode for low-
stress distribution pipelines. Most incidents on distribution pipelines 
result from the accumulation of gas that has leaked from the pipeline. 
Section 192.703(c) already requires that hazardous leaks be repaired 
promptly, but operators may repair leaks at a later time if determined 
not to be hazardous. PHMSA considers it important that operators 
monitor these leaks to assure that hazardous conditions do not develop. 
At the same time, PHMSA recognizes that some operators repair all leaks 
when found and does not intend to require these operators to develop 
unnecessary monitoring programs. PHMSA also recognizes that most 
operators that do not repair all leaks when found already have leak 
monitoring programs. PHMSA has revised the final rule to require that 
risk mitigation measures include a leak monitoring program except if 
all leaks are repaired when found. PHMSA has also modified Sec.  
192.1007(e) to clarify that operators who repair all leaks when found 
do not have to categorize them for hazard for the sole purpose of 
performance monitoring.
    PHMSA does not consider it necessary to delineate the contents of 
an effective leak management program in the rule. Operators should 
develop a program based on their knowledge of their pipeline system. 
The GPTC Guide also offers guidance regarding how to develop an 
effective leak management program.
    Comment Topic 15: State authority.
    Florida PSC commented that States must have the authority to 
review, analyze, and approve or deny an operator's distribution IM 
program. They contended that the programs will be unique and complex. 
They noted that evaluation of a program will require judgment and 
suggested that reaching an agreeable program may require several years.
    NAPSR commented that the rule should explicitly recognize the need 
to include flexibility for States to accommodate their specific 
circumstances. They noted that this need was recognized explicitly in 
PHMSA's report to Congress on DIMP.
    PHMSA response: Certified state regulators who exercise 
jurisdiction over intrastate distribution pipeline operators have the 
authority and obligation to inspect operator compliance with this final 
rule; however, PHMSA does not require an operator's plan to be approved 
by the regulatory authority. Regulators must review operator IM 
programs and direct changes in cases in which they determine that the 
operator's program does not comply with the rule. PHMSA recognizes that 
IM programs will be unique and can be complicated (reflecting 
complexity in some distribution systems) and that these programs will 
likely take several years to reach maturity. As noted earlier, PHMSA 
plans to develop and provide training and qualification programs for 
state inspectors. PHMSA intends to provide states with background 
information necessary for them to conduct reviews and to avoid large 
inconsistencies in the approach to IM across the country.
    PHMSA's statements in this rulemaking record have consistently 
recognized that states must have the flexibility to address their 
specific circumstances. Nothing in the language of the rule restricts 
this flexibility. PHMSA understands that operator IM programs will vary 
based on differences in their pipelines and operations and that states 
need to consider each program on its merits. The rule establishes high-
level requirements but leaves operators and their regulators (mostly 
states) to determine how best to do it in each individual circumstance.
    Comment Topic 16: IM program evaluation and improvement.
    A number of comments addressed proposed requirements to evaluate 
and improve distribution IM programs.
    a. Continual evaluation.

[[Page 63918]]

    APGA, Iowa, and a number of operators objected to the proposed 
requirement in Sec.  192.1007(f) that an operator ``must continually 
re-evaluate threats and risks on its entire system.'' These commenters 
suggested that such re-evaluation be required on a periodic basis. They 
noted that continuous re-evaluation is unreasonable and that it doesn't 
follow from the concept of ``periodic evaluation and improvement'' (the 
title of this proposed paragraph).
    PHMSA response: PHMSA considers that operators should evaluate the 
effectiveness of their IM programs on a routine basis, i.e., 
``continually.'' That is a basic concept of an effective IM program 
that has been used in other IM regulations. Nonetheless, because of the 
overwhelming concern raised by commenters about this term, PHMSA has 
revised the final rule to require that such re-evaluations occur on a 
periodic basis, based on the complexity of the system and changes in 
factors affecting the risk of failure; however, re-evaluations must 
occur at least once every 5 years.
    b. Continuous improvement.
    One operator noted that making changes solely to show 
``improvement'' can be disruptive and ultimately detrimental to 
performance.
    PHMSA response: Continuous improvement is an important part of the 
philosophy underlying IM. Where evaluation of an IM program identifies 
changes that can improve the program's effectiveness, these changes 
should be incorporated into the program. The ultimate goal is to 
improve safety. Improvement cannot be realized without change.
    c. Evaluation frequency.
    NAPSR objected to the proposed requirement that operators must 
determine the appropriate period for conducting complete program 
evaluations based on the complexity of their systems and changes in 
factors affecting the risk of failure and that the interval selected 
may not exceed five years. NAPSR suggested that an evaluation be 
required annually (not to exceed 15 months), similar to the evaluation 
interval for other programs required by Part 192. NAPSR believes that 
five years is too long, noting that the stakeholder conclusion was that 
an annual review should be required.
    PHMSA response: An operator should re-evaluate its IM program 
whenever changes occur in the system that may result in new knowledge, 
new threats or other information that would permit improvement in the 
IM program. For some operators, this may be more frequent than an 
annual basis. For other operators, these types of changes may occur 
seldomly. Therefore, we are retaining the requirement for all operators 
to evaluate their program at a period appropriate for their system and 
at least every five years, as proposed in the NPRM.
    d. Required improvement at specific frequency.
    Several operators objected to the proposed requirement to 
periodically improve each IM element in Sec.  192.1005(b) (as well as 
the requirement to continually refine and improve in proposed Sec.  
192.1007(a)(4)). They maintained it may not be reasonable to 
``improve'' all elements at all times, and that enforcement of such a 
requirement would pose problems. They suggested that the proposed 
requirements to ``improve'' be replaced with a requirement to review 
and adjust/update as needed to meet distribution IM goals. One operator 
read proposed Sec.  192.1007(d) to require that operators implement new 
mitigation measures annually and requested we clarify that this is not 
required.
    PHMSA response: PHMSA's intent was to encourage operators to 
consider potential improvements to their IM programs routinely as a 
regular part of their activities. To improve clarity, PHMSA has revised 
the final rule to require that programs be reviewed on a periodic basis 
and improved as needed. Section 192.1007(d) requires that operators 
determine and implement measures to reduce risks. Section 192.1007(f) 
requires that operators reassess their programs periodically, but at 
least every five years. Nothing in the rule requires that new 
mitigation measures be implemented at any periodicity.
    e. Redundant requirements.
    One operator suggested we delete the proposed requirement in Sec.  
192.1005(b) that operators have procedures for ``periodically improving 
each of the required elements''. The operator noted that periodic 
evaluation and improvement is, itself, an element, and that this makes 
the proposed requirement in Sec.  192.1005(b) confusing, at best.
    PHMSA response: PHMSA agrees and has revised the final rule. We 
have revised section 192.1005 to specify that an operator must develop 
and implement a written IM program that addresses the required elements 
in Sec.  192.1007. Section 192.1007 now provides that the IM plan must 
have procedures to develop and implement the required elements. One of 
the required elements is to refine and improve the program as needed 
(section 192.1007(a)(4)).
    f. Consideration of threats in re-evaluation.
    Another operator suggested that PHMSA delete the requirement in 
proposed Sec.  192.1007(f) that an operator ``consider the relevance of 
threats in one location to other areas'' as part of its periodic re-
evaluation. This operator contended that this is covered by the 
requirement in proposed Sec.  192.1007(c) that threats be considered in 
all areas.
    PHMSA response: PHMSA recognizes that a thorough evaluation of 
threats in any area should identify threats of concern regardless of 
whether they affect other areas of an operator's system. Still, PHMSA 
considers that knowledge that a threat affects a system in one 
location, and how that threat manifests itself, can inform 
consideration of that threat in other locations. PHMSA has retained 
this requirement in the final rule.
    Comment Topic 17: Permanent marking of plastic pipe.
    The NPRM preamble posed a number of questions concerning permanent 
marking of plastic pipe. These questions elicited a number of 
responses.
    a. Support for marking
    One operator strongly supported requirements to mark plastic pipe, 
providing a list of attributes the operator believes should be marked 
every 18 inches.
    b. Against marking
    AGA, supported by at least one operator, suggested that plastic 
pipe marking should be considered outside of DIMP. Both maintained that 
manufacturer input is needed on this subject and that most operators do 
not possess the data infrastructure to record and properly manage data 
from each piece of plastic pipe. They contended that the knowledge 
requirements of proposed Sec.  192.1007(a) are sufficient to manage 
pipeline integrity.
    Several operators suggested that ASTM should address pipe marking 
and that PHMSA should not establish requirements in this area. Some 
operators, GPTC, Iowa and one plastic pipe consulting company noted 
that the current version of ASTM D2513, which is not yet referenced in 
Part 192, includes permanent marking requirements. Some operators noted 
that fittings are a separate concern and suggested that they would 
present other problems/considerations.
    PHMSA response: We did not propose a requirement to mark plastic 
pipe. Rather, we asked for comment to elicit better information about 
various pipe types and their performance history. PHMSA believes 
operators may be able to better manage risk with better information 
regarding pipe

[[Page 63919]]

performance. We plan to address this issue outside this rulemaking.
    Comment Topic 18: Continuing surveillance.
    Iowa and a large operator suggested that we revise Sec.  192.613, 
Continuing surveillance, to exclude distribution systems subject to 
proposed new Subpart P because it will be a redundant and unnecessary 
requirement if DIMP is implemented as proposed.
    PHMSA response: PHMSA disagrees. While some aspects of IM may 
overlap activities operators perform as part of continuing 
surveillance, there are requirements in Sec.  192.613 that are not 
duplicated in this rule. For example, DIMP does not specifically 
require an operator to recondition or phase out an unsatisfactory 
segment when no immediate hazard exists.
    Comment Topic 19: Information gathering.
    The NPRM proposed (Sec.  192.1007(a)) that an operator must 
demonstrate an understanding of the gas distribution system. NAPSR 
suggested that the proposed rule should require operators to assemble 
information about their systems that is ``reasonably available.'' NAPSR 
maintained that it is unreasonable to suggest operators should develop 
the best understanding possible. NAPSR further maintained that the 
proposed language fails to list useful sources of information and 
implies an unbounded need for knowledge. NAPSR would revise the 
language to more completely identify the sources of information to be 
used and would limit the requirement to identify system characteristics 
and environmental factors (proposed sub-paragraph (a)(1)) to those 
``reasonably'' necessary to assess threats and risks.
    PHMSA response: PHMSA understands NAPSR's concern. PHMSA does not 
intend that operators expend excessive effort, review every record 
available in their archives, or explore every nuance about their 
pipelines. At the same time, PHMSA expects that operators will devote 
sufficient effort to develop as thorough an understanding of their 
pipelines as they can while using reasonable effort. PHMSA has revised 
the final rule to require that operators develop an understanding of 
their pipeline systems ``from reasonably available information.'' PHMSA 
considers that this strikes the appropriate balance. Because of this 
change, PHMSA does not consider it necessary to modify subparagraph 
(a)(1) to limit information to assess threats and risk to 
``reasonably'' necessary information.
    PHMSA has not included in the rule a list of information that 
operators should use to find information about their pipeline systems. 
An operator is in the best position to determine what information is 
most relevant to its system. PHMSA is concerned that any such list 
would become limiting (i.e., operators and regulators would not 
consider sources not included in the list) or would create unnecessary 
burdens (e.g., a perceived obligation to review a source listed even 
though it would not reveal useful information).
    Comment Topic 20: Knowledge of pipeline.
    PHMSA also received other comments regarding the need for an 
operator to know its pipeline:
    a. Environmental factors.
    APGA, GPTC, and a large operator suggested that we clarify 
``environmental factors'' in Sec.  192.1007(a)(1) to mean factors 
(e.g., washouts, landslides) that could pose a hazard to the pipe as 
opposed to factors that would make the environmental consequences of 
accidents worse. They noted that gas does not produce significant 
environmental consequences as would oil or other hazardous liquids.
    PHMSA response: PHMSA concludes that no change is needed. This 
paragraph already refers to ``environmental factors that are necessary 
to assess the applicable threats and risks to its gas distribution 
pipeline'' and does not refer to consequences. PHMSA notes that 
washouts and landslides are extreme examples of ``environmental 
factors'' that might be of concern. Other environmental factors that 
might need to be considered include soil corrosivity or location in an 
area likely to experience a greater-than-normal amount of excavation 
activity.
    b. Normal activities.
    One large operator suggested that the ``normal activities'' through 
which operators are expected to glean additional knowledge (proposed 
192.1007(a)(3)) be specifically limited to, ``normal activities 
performed in the construction, operations, and maintenance of gas 
distribution systems in accordance with the applicable requirements of 
Part 192.''
    PHMSA response: PHMSA does not consider this limitation necessary. 
Operators are expected to take advantage of opportunities to improve 
system knowledge through any of their normal activities, including 
those that go beyond those activities specifically required by Part 
192. For example, excavation that exposes the pipeline system presents 
a significant opportunity to learn additional information, but few 
excavations are conducted specifically to comply with Part 192 
provisions.
    c. Additional activities.
    PA PUC would expand the list of activities through which operators 
are expected to gain additional knowledge to include maintenance and 
management policies in addition to past design and operations (Sec.  
192.1007(a)(2)). They would revise proposed Sec.  192.1007(a)(4) to 
replace the requirement to ``continually'' refine and improve knowledge 
with a requirement to ``develop an ongoing process by which the 
operator's knowledge of its system will be refined and improved.''
    PHMSA response: PHMSA's use of ``operations'' in this context was 
intended in its broadest sense--activities associated with operating 
the system, including maintenance. This comment indicates that it is 
possible to read the proposed language as excluding maintenance. PHMSA 
has modified the final rule to reflect that information gained from 
operations and maintenance should be considered. PHMSA considers the 
phrase ``management policies'' to be vague and subject to 
misunderstanding and has not included it in the final rule. Changes 
associated with eliminating the implication that operators must 
``continually'' improve their knowledge have been described above.
    d. Design and operations information.
    One operator would delete proposed paragraph (a)(2), which would 
require that an operator understand the information gained from past 
design and operations, because it is unclear how compliance can be 
achieved or demonstrated. Another operator would add ``design and 
operations'' to the requirement in proposed paragraph (a)(1) to 
understand the system.
    PHMSA response: PHMSA has revised paragraph 192.1007(a)(2) to 
require that operators consider lessons from past design and operation 
experience, rather than that they ``understand'' them. For example, 
operators could involve maintenance foremen/supervisors in their 
information collection activities, surveying them to ask about unusual 
circumstances they have encountered in their activities and/or asking 
them to review resulting system descriptions and identify any 
information they believe useful that is not already included. Good 
information only has an effect when it is used. Compliance will be 
reviewed by assuring that an operator has implemented means to gather 
this information and has considered the information.
    e. Terminology.

[[Page 63920]]

    An operator would change ``piping system'' and ``piping and 
appurtenances'' in paragraph (a)(5) to ``pipeline'' for consistency 
with the definition of pipeline in Sec.  192.3.
    PHMSA response: PHMSA has made the suggested change.
    Comment Topic 21: Threat identification.
    Several changes were suggested to the proposed requirement for 
operators to identify threats in Sec.  192.1007(b). Paragraph (b) 
listed categories of threats and potential sources of information an 
operator must consider.
    a. Data sources.
    APGA would delete reference to ``one call experience'' because the 
meaning of this term is unclear and would add nothing beyond the 
operator's own damage experience. One operator would limit ``incident 
history'' as a data source to incidents requiring reporting per Sec.  
191.3. Another operator suggested that the list of threats be revised 
to match the list in the annual report, noting that there are minor 
inconsistencies in the wording of the proposed requirement. An operator 
suggested that ``and any other concerns that could threaten the 
integrity of the pipeline'' is unlimited and thus unreasonable.
    PHMSA response: Because relevant information from one call 
experience would overlap with the operator's own excavation damage 
experience, PHMSA agrees that listing one-call as a source of 
information for threat identification is redundant and has made the 
suggested change. The term incident, as used in the regulations, is 
commonly understood to refer to incidents as defined in Sec.  191.3. 
The list of categories in this final rule is consistent with the 
categories in the annual report. What minor wording inconsistencies 
exist are due to use of the list in a sentence structure in the rule. 
PHMSA considers the language regarding ``any other concerns'' to be 
consistent with the ``other'' category of threats on the annual report 
form.
    b. Sources of information.
    NAPSR and Iowa contended that the proposed language unnecessarily 
restricts sources of information an operator may use (i.e., ``An 
operator must gather information from the following sources''). 
Instead, NAPSR would require that an operator consider sufficient data 
to identify existing and potential threats and would identify the 
proposed list as sources an operator ``may include, as appropriate.''
     PHMSA response: PHMSA agrees and has revised the paragraph to 
clarify that the information sources an operator must use to identify 
threats are not limited to those listed.
    c. Third party damage.
    A consultant noted that the threat of third-party damage should not 
be as significant for small operators as for large because small 
operators exercise better control and/or it is easier to patrol their 
systems. At the same time, he noted that his own analyses of small 
systems (i.e., master meter) suggests that threats other than third-
party damage may be as significant or more significant for small 
operators than for large.
    PHMSA response: Each operator will be required to determine the 
relative importance of threats for its distribution pipeline as part of 
implementing this final rule. An operator will be able to factor in the 
degree of control it has over its system when determining the relative 
importance of threats. We have not revised the language in the final 
rule.
    Comment Topic 22: Risk assessments.
    Several comments addressed the proposed requirements for risk 
assessment in Sec.  192.1007(c).
    a. Subdividing a pipeline for risk analysis.
    NAPSR and one operator commented that subdivision of a distribution 
system for risk analysis may not be geographical, as they believe the 
proposed language implied. They noted that similarity of 
characteristics and environment may be more important factors for 
subdividing analyses than location. The operator suggested that class 
location might be an appropriate factor. Other operators suggested that 
the concept of ``regions'' for analysis is not clear and commented that 
the suggestion for grouping by consistent risk or actions be 
eliminated; they noted that one cannot group by common risk without 
analyzing risk first and that suggesting otherwise results in circular 
logic.
    PHMSA response: PHMSA agrees that subdividing a distribution 
pipeline system for risk analysis could be done on a basis other than 
geography. PHMSA has modified the final rule to clarify that geographic 
proximity is only an example of how a region may be defined, by 
inserting ``e.g.,'' before this description and by adding another 
example. PHMSA agrees that the concept of creating regions for risk 
analysis on the basis of reasonably consistent risk results is circular 
logic and has deleted this criterion.
    b. Evaluate threats.
    One operator suggested that the requirement to evaluate threats as 
part of the risk assessment be limited to known threats because it is 
impossible to rank the importance of ``potential'' threats.
    PHMSA response: PHMSA disagrees. In many cases, ``known threats'' 
are treated as threats that have resulted in an effect on the pipeline, 
while other threats are, at best, ``potential.'' For example, earth 
movement might not be considered a ``known threat'' for pipe located in 
an area where landslides can be expected but where the pipeline has 
never been affected by one. It would be important, though, to consider 
the likelihood that the ``potential'' threat of earth movement might 
affect this pipe as part of an operator's IM program. It should also be 
possible to collect information about the relative likelihood of a 
landslide to consider this threat, including ranking its importance and 
determining whether mitigative actions are appropriate. PHMSA has 
retained the requirement to consider potential threats in the final 
rule.
    c. Defining terms.
    One operator suggested that the term ``relative probability'' 
should be defined. Another operator suggested that the term 
``probability'' be replaced with ``likelihood'' throughout the proposed 
rule, to eliminate the implication a rigorous mathematical process is 
required.
    PHMSA response: PHMSA agrees that use of the terms ``probability,'' 
``relative probability,'' and ``prioritize'' could imply a need for a 
mathematical process. PHMSA has noted confusion about the need for 
quantified estimates of risk throughout the discussions related to 
distribution integrity management. For complex systems where there is a 
wealth of data, a mathematical analysis of risk may be the best way to 
understand the relative importance of various threats. For most 
distribution pipeline systems, however, simpler techniques (as 
described in the GPTC Guide, for example) should suffice. PHMSA has 
revised the final rule, to avoid further confusion, to replace these 
terms with ``importance,'' ``relative importance,'' and ``rank.'' One 
useful reference tool could be the GPTC Guide for guidance on non-
mathematical methods of evaluating risk.
    d. Prioritize risk.
    One operator suggested that the requirement to estimate or 
prioritize risk should be eliminated, and that the requirement be 
limited to determining the relative probability of threats. The 
operator contended that each pipe material carries its own threats, and 
that it is difficult to prioritize one over another. Prioritization is 
too difficult and may not meet the intended purpose because there is 
often insufficient data to quantify.

[[Page 63921]]

    PHMSA response: PHMSA disagrees with eliminating a requirement to 
prioritize risk. Prioritizing actions is an inherent part of managing 
any activity. It is needed to apply limited resources where they will 
do the most good. With respect to IM, PHMSA firmly believes that this 
prioritization should consider risk, i.e., both likelihood and 
consequences. For example, an operator may face two threats that can 
produce different consequences. It would be inappropriate to apply 
resources to the threat with a slightly higher likelihood of occurrence 
and not to the second threat if the consequences that could result from 
the second threat are much greater. The risk (i.e., likelihood and 
consequences) of the second threat is higher.
    PHMSA understands that it is easier to rank threats when only a 
single variable changes, and that limiting consideration to threat 
ranking by material would be easier. This would not, however, assure 
the most effective application of safety resources, which an operator 
must apply across its entire pipeline, regardless of differences in the 
material of construction.
    Comment Topic 23: Performance measures.
    A number of comments were made concerning proposed requirements for 
performance measures. In the NPRM, PHMSA proposed that an operator must 
develop and monitor performance measures to evaluate the effectiveness 
of its IM program and required the performance measures to include the 
number of hazardous leaks, categorized by cause and by materials, 
number of excavation damages, the number of excavation tickets, the 
number of EFVs installed, and the total number of leaks categorized by 
cause. The proposal required an operator to develop additional measures 
necessary to evaluate the effectiveness of controlling each identified 
threat.
    a. NAPSR suggested an additional performance measure, which could 
be derived from data already reported: the amount or ratio of non-
state-of-the-art pipe in an operator's system.
    PHMSA response: PHMSA does not agree that this is an appropriate 
national measure. This measure was considered in the work of the 
stakeholder groups. The final report of that work did not recommend 
this as a national performance measure.\9\ One reason for this 
conclusion was that it could be misleading. Much older pipe (e.g., cast 
iron) that has been properly maintained operates quite safely. At the 
same time, problems have sometimes been experienced with new pipe 
(e.g., specific heats of plastic pipe). PHMSA recognizes that many 
states are working with their operators to support pipe replacement 
programs intended to replace non-state-of-the-art pipe, and PHMSA 
encourages those efforts. PHMSA expects that the states will monitor 
the amount of non-state-of-the-art pipe remaining in an individual 
operator's system as part of such replacement programs. Reporting this 
parameter on a national basis is not needed to facilitate required pipe 
replacement programs.
---------------------------------------------------------------------------

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

    b. The proposed performance measures included the number of 
hazardous leaks eliminated or repaired and the number of excavation 
tickets. A consultant suggested the need for more precise definitions 
of ``ticket'' and ``leak'' as the use of these terms is imprecise 
across the industry. Two operators agreed that a definition of 
excavation ticket is needed. Another suggested that this be limited to 
``tickets received from the notification center where marking is 
required.'' Another suggested that PHMSA should not define this term.
    An operator suggested that damages should be normalized per 100 
tickets. The operator noted that differing levels of construction 
activity could imply that an operator's IM program is more, or less, 
effective but that this is totally outside the operator's control. 
Another operator suggested that the number of excavation tickets has no 
value as a performance measure, and that this data is expensive to 
generate. This operator explained that tickets are often issued for 
areas in which there is no gas pipe in the vicinity of planned 
excavation and that tickets may be renewed. These operators also 
suggested that tickets are issued for areas of differing size. They 
contended that, because of all of these differences, this data is not 
useful to normalize excavation damage information.
    PHMSA response: The purpose of the measure to report the number of 
excavation tickets is to normalize excavation damage information in 
order, for example, to help determine whether reduced excavation 
damages are a result of improved damage prevention programs or less 
construction (excavation) activity. Normalization is necessary 
precisely for the reason identified by the commenters--changes in the 
amount of construction activity will affect the number of excavation 
damages but are outside the control of an operator's IM program. PHMSA 
expects that analyses will likely normalize per 100 tickets but notes 
that this is a simple arithmetic adjustment if the basic data is 
available. Operators are required to participate in one-call programs 
to receive notification of planned excavation activity, i.e., 
tickets.\10\ PHMSA thus concludes that collecting this data will not be 
expensive. Reporting of this parameter has thus been retained in the 
final rule.
---------------------------------------------------------------------------

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

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

[[Page 63922]]

operators have appropriate measures. Iowa suggested that the 
requirements are not needed if the annual report forms are modified to 
include the desired information.
    The NPRM preamble noted that a reduction of incidents will be the 
ultimate indicator of performance, but that it will take years to see 
trends in this data. The NPRM stated that the proposed performance 
measures would provide a measurement during the interim period while 
these trends are developing and invited the public to suggest other 
measures for this interim period. In response, one operator commented 
that there should be no interim measures, only permanent. Another 
operator, apparently reflecting the same concern about potential 
changes in reporting requirements, suggested that performance measures, 
once in place, should remain stable for at least 5 years. The operators 
noted that time is needed to determine the effectiveness of such 
measures and to implement data system changes and personnel training.
    PHMSA response: Measuring performance is a key element of all 
integrity management programs. IM rules for other types of pipelines 
also include this element. At its basic level, IM is an iterative 
process consisting of analysis of risks, implementing actions to reduce 
risk, monitoring to evaluate the effectiveness of those actions, and 
modifying the program as needed. Without performance monitoring, the 
feedback portion of the process cannot occur.
    On a macro basis, PHMSA agrees that the number of incidents is the 
ultimate measure of the effectiveness of efforts to assure distribution 
safety. PHMSA will continue to collect incident data and will use that 
data to evaluate the effectiveness of its regulatory program. This 
measure is not useful to individual operators, however, precisely 
because the number of incidents is small. Many operators will 
experience no incidents in a year. Few, if any, will experience more 
than one. Operators must use other non-incident measures to evaluate 
the effectiveness of their own programs. PHMSA continues to conclude 
that it is appropriate that the rule require these actions.
    As discussed in the NPRM, it will take several years for incident 
data to indicate any trend as a result of the actions required by this 
rule. PHMSA considers it necessary to collect additional performance 
measures to permit preliminary judgments concerning the effectiveness 
of this regulation in the interim. This does not mean that these 
measures are not ``permanent.'' The final rule retains the requirement 
to submit performance measures in the annual report.
    d. A citizens group commented that key information, such as 
hazardous leaks repaired by cause and material, must be publicly 
available. NAPSR and the Pennsylvania PSC also suggested that data 
reported to PHMSA should be in a database accessible to states, rather 
than requiring duplicate reporting. The Arizona Corporation Commission, 
taking a contrary position, suggested that reports sent to PHMSA should 
also be required to be submitted to States exercising jurisdiction.
    PHMSA response: All IM performance measures submitted to PHMSA will 
be part of the annual report filed by distribution pipeline operators. 
Annual report information is available to the public via the PHMSA web 
site. In addition, we are requiring operators to report performance 
measure information to states exercising jurisdiction.
    e. NAPSR and Iowa suggested that the number of leaks repaired/
replaced by material be added as a national performance measure, as 
this is useful information relevant to the effectiveness of IM. These 
commenters also suggested that the requirement to report information 
concerning leaks be limited to information that is known or available. 
They noted that operators may not excavate leaking pipe, but may 
replace it and retire leaking sections in place. In that instance, they 
may not know the cause of the leak, or the particular material on which 
it occurred (e.g., whether on pipe body or a valve/fitting).
    PHMSA response: The stakeholder groups considered the use of leaks-
by-material as a national performance measure but rejected it as a 
measure in part because of the potential for misinterpretation. Many 
leaks are caused by excavation damage or other outside forces, in which 
case the pipe material is not of principal importance. The groups 
concluded that this would be useful information for operators in 
evaluating the effectiveness of their own programs but that it should 
not be reported on a national basis. PHMSA agrees.
    PHMSA notes that operators have been required to report the number 
of leaks eliminated/repaired, by cause, for many years as part of their 
annual reports. Operators have presumably filed these reports based on 
the information that they have available. PHMSA is not aware of 
complaints that unnecessary effort has been required simply to 
determine a cause for reporting purposes. PHMSA therefore does not 
consider that any explicit limitation is necessary on the information 
to be used to identify the cause of repaired leaks.
    f. An operator suggested that specific causes to which leaks are to 
be attributed should be listed, and further that the list of causes 
must include ``unknown.'' The operator suggested that meaningful 
comparisons require a limited number of specified causes. The operator 
also noted that lines are often retired in place rather than being 
removed, and that the cause of leaks is thus not always known.
    PHMSA response: Performance reporting will be via the annual 
report. The annual report currently requires that operators report 
leaks repaired by cause. It lists a number of causes for this purpose, 
including ``other.'' Any revisions to the form for purposes of IM 
performance measures will similarly provide a list of causes. See the 
annual report comment topic for more information regarding changes to 
the annual reporting form.
    g. NAPSR, Iowa, and one operator suggested that we clarify ``any 
additional measures'' described in proposed Sec.  192.1007(e)(1)(vii) 
are additional measures the operator selects.
    PHMSA response: PHMSA has made this clarification.
    h. One operator suggested that PHMSA should establish guidance for 
implementing uniform metrics, since these are needed for a performance-
based process.
    PHMSA response: PHMSA will use four measures to evaluate the 
overall effectiveness of this regulation. These measures are specified 
in this rule, will be listed on the revised annual report form, and 
will be in the instructions for completing the annual report. As 
discussed above, PHMSA expects that there will be some inconsistencies 
in reporting of at least one measure (number of excavation tickets); 
however, the data submitted with the annual report will be sufficient 
for PHMSA to evaluate the effectiveness of the regulation.
    PHMSA does not consider that further guidance is necessary to 
assure that operators are collecting other performance measure data 
uniformly, as that data will be used by individual operators to 
evaluate the effectiveness of their programs. An individual operator 
should collect and use the data it collects consistently; however, 
differences between operators do not matter.
    Comment Topic 24: Regulatory analysis.
    We received a number of comments concerning the regulatory analysis

[[Page 63923]]

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

[[Page 63924]]

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

[[Page 63925]]

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

[[Page 63926]]

(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.
------------------------------------------------------------------------

[[Page 63927]]

               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.

[[Page 63928]]

        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.

[[Page 63929]]

                      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

[[Page 63930]]

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

[[Page 63931]]

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

[[Page 63932]]

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.

[[Page 63933]]

    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

0
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.

[[Page 63934]]

0
2. Section 192.383 is revised to read as follows:

Sec.  192.383  Excess flow valve installation.

0
(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.
0
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

[[Page 63935]]

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

[[Page 63936]]

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