Pipeline Safety: Integrity Management Program for Gas Distribution Pipelines, 63906-63936 [E9-28467]

Agencies

• Pipeline and Hazardous Materials Safety Administration
• DEPARTMENT OF TRANSPORTATION

[Federal Register Volume 74, Number 232 (Friday, December 4, 2009)]
[Rules and Regulations]
[Pages 63906-63936]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E9-28467]



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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

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

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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: https://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: https://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 https://www.regulations.gov, by following the steps above.

    Note: PHMSA will post all comments without changes or edits to 
https://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.

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II. Comments on the NPRM

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

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

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not available to the entire industry is unjustified. These commenters 
noted that PPDC issues summary reports, that trade associations (who 
participate in PPDC) provide information to their members, and that 
PHMSA has issued advisory bulletins concerning significant PPDC 
conclusions. Many operators commented that they would not have the time 
or resources to review detailed failure information on their own, and 
that the information currently provided by the trade associations and 
PHMSA advisories is useful to them.
    Some commenters suggested that the rule require operators to make 
use of this information. AGA and one operator suggested that the 
requirement to report plastic pipe failures be replaced with a 
requirement that operators consider industry and government advisories 
in evaluating plastic pipe performance as part of their DIMP programs. 
They believe this would be more effective in addressing PHMSA's 
underlying concern of operators not considering relevant information 
than would mandatory reporting. All who addressed this subject agreed 
that replacing the current system with mandatory reporting of all 
failures would be unreasonably burdensome and would not improve 
knowledge or safety. PPDC commented that mandatory reporting is not 
needed as they have the necessary structure and participation. PPDC 
suggested that it would take years to collect enough data to duplicate 
the information they already have on hand.
    PHMSA response: PHMSA is persuaded that the data collection burden 
is not warranted at this time given the current system of PPDC analysis 
of plastic pipe failure trends and dissemination of lessons learned 
from this analysis via PPDC reports and trade association 
communications and through our advisories. The final rule does not 
include the requirement to report all plastic pipe failures.
    The proposed requirement included reporting failures of couplings 
used with plastic pipe. PHMSA has retained this requirement for 
compression couplings. This final rule includes a requirement that 
operators report failures of compression coupling as part of their 
annual reports. This provision was an included part of proposed 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

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

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assessments (i.e., physical inspection) of the portions of their 
pipelines in high consequence areas.\1\ The proposed rule did not 
include a provision for distribution pipeline operators to conduct such 
assessments. Transmission pipeline operators were required to develop 
and implement IM plans in one year.\2\
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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 pipe