of uncertainty when determining if an anomaly meets any repair
criterion.
    C.2. Should anomalous conditions in non-HCA pipeline segments
qualify as repair conditions subject to the IM repair schedules? If so,
which ones? What projected costs and benefits would result from this
requirement?
    1. INGAA suggested that new criteria are not needed, commenting
that operators generally treat non-HCA anomalies in a manner similar to
HCA anomalies, except for response time. INGAA stated that industry
costs to address non-HCA anomalies should be nominal unless immediate
response is required because this is consistent with current operator
practice, which INGAA stated is to apply ASME/ANSI B31.8S response
criteria for anomalies both inside and outside HCAs.
    2. Texas Pipeline Association and Texas Oil & Gas Association
commented that differing repair criteria, if any, should be based upon
the population at risk, since there is no valid engineering basis for
treating anomalies differently depending on location.
    3. Atmos and Northern Natural Gas suggested that non-HCA anomalies
should be treated like HCA anomalies, although additional schedule
flexibility should be allowed. Northern reported that it applies HCA
metal loss criteria everywhere because it is prudent, although response
time differs for non-HCA anomalies. Northern reported that it has
expended approximately $7.7 million on anomaly repairs, $7 million of
which was outside an HCA.
    4. Kern River agreed that IM schedules are too stringent to apply
everywhere and providing schedule flexibility will reduce costs.
    5. MidAmerican disagreed with the suggestion that non-HCA and HCA
anomalies be treated alike. MidAmerican commented that it is illogical
to back off from focusing sooner on anomalies that pose greater risks.
    6. California Public Utilities Commission commented that all
locations identified by the method described in paragraph 1 in the
definition of HCA in Sec.  192.903 should be subject to HCA repair
criteria.
    7. Pipeline Safety Trust, Accufacts, and NAPSR commented that the
same repair criteria and response schedule should apply regardless of
where an anomaly is located. These commenters contended that there is
no logical justification for different treatment, that any risk to the
pipeline and public safety should be resolved, and that a pipeline
accident anywhere is seen by the public as a failure to exercise
adequate control of pipeline safety. NAPSR, in particular, suggested
that all anomalies should be repaired immediately, regardless of where
they are located.
    8. Iowa Utilities Board, Iowa Association of Municipal Utilities,
GPTC, Nicor, Ameren Illinois and an anonymous commenter contended that
HCA repair criteria should not be applied outside HCAs. These
commenters noted that there has been no demonstrated safety need for
new criteria, that non-HCA anomalies are adequately addressed under
existing operations and maintenance requirements, and that the cost to
apply HCA repair criteria everywhere is not justified. IAMU
particularly noted that

existing requirements are adequate for small, low-pressure transmission
pipelines such as those operated by its members.
    9. A private citizen supported application of HCA repair criteria
in non-HCA areas, particularly where there are ``receptors,'' which the
commenter defines as ``something which needs to be protected.''
Response to Question C.2 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA
proposes to modify the general requirement for repair of pipelines to
include immediate repair condition criteria, one-year conditions, and
monitored conditions. The definition of these conditions would be the
same as the existing definitions for covered segments (i.e., HCA
segments) in the IM rule; however, PHMSA proposes that those conditions
that must be repaired within one year in a HCA segment would be
required to be repaired within two years in a non-HCA segment. Defects
that meet any of the immediate criteria are considered to be near-term
threats to pipeline integrity and would be required to be repaired
immediately regardless of location.
    PHMSA believes that establishing these non-HCA segment repair
conditions are important because, even though they are not within the
defined high consequence locations, they could be located in populated
areas and are not without consequence. For example, as reported by
operators in the 2011 annual reports, while there are approximately
20,000 miles of gas transmission pipe in HCA segments, there are
approximately 65,000 miles of pipe in Class 2, 3, and 4 populated
areas. PHMSA believes it is prudent and appropriate to include criteria
to assure the timely repair of injurious pipeline defects in non-HCA
segments. These changes will ensure the prompt remediation of anomalous
conditions on all gas pipeline segments while allowing operators to
allocate their resources to high consequence areas on a higher priority
basis.
    C.3. Should PHMSA consider a risk tiering--where the conditions in
the HCA areas would be addressed first, followed by the conditions in
the non-HCA areas? How should PHMSA evaluate and measure risk in this
context, and what risk factors should be considered?
    1. INGAA, and many pipeline operators, opposed the suggested
tiering. They commented that anomalies meeting response criteria should
be addressed in an appropriate time frame whether inside or outside
HCAs.
    2. AGA, supported by many of its operator members, suggested that
PHMSA not adopt any risk tiering beyond the current requirements to
focus first on HCA anomalies. AGA noted that outside factors, e.g.,
permitting, affect the timing and the sequence of repairs.
    3. Texas Pipeline Association and Texas Oil & Gas Association
commented that PHMSA should allow risk tiering system-wide, not just in
differentiating between responses in and outside HCA. The associations
suggested that this could be an improvement to requirements addressing
anomalies. At the same time, they noted the description in the ANPRM is
sketchy and requested PHMSA propose specific requirements for comment.
    4. Iowa Association of Municipal Utilities commented that no new
requirements are needed, and that the existing requirements are
sufficient for the small, low-stress transmission pipelines operated by
its members.
    5. Atmos commented that the risk tiering concept is confusing and
stated that it was considered and rejected when the initial IM rules
were promulgated.
    6. Northern Natural Gas commented that allowing a longer response
time for anomalies outside HCA would be a form of risk tiering. The
company reported it has incorporated this practice in its procedures.
    7. Accufacts agreed that a focus on HCA anomalies is needed but
cautioned against ignoring anomalies outside HCAs. Accufacts noted the
progression of an anomaly to failure does not depend on whether or not
it is located in an HCA.
Response to Question C.3 Comments
    PHMSA appreciates the information provided by the commenters.
Current regulations do not prescribe response timeframes for anomalies
outside HCAs. As stated by Northern Natural Gas, allowing a longer
response time for anomalies outside HCAs (compared to response times
for anomalies inside HCAs) would be a form of risk-tiering. PHMSA is
proposing such an approach, which would establish three timeframes for
performing repairs in non-HCA areas: Immediate repair conditions, 2-
year repair conditions, and monitored conditions. These changes will
ensure the prompt remediation of anomalous conditions on all gas
pipeline segments, while allowing operators to allocate their resources
to those areas that present a higher risk.
    C.4. What should be the repair schedules for anomalous conditions
discovered in non-HCA pipeline segments through the integrity
assessment or information analysis? Would a shortened repair schedule
significantly reduce risk? Should repair schedules for anomalous
conditions in HCAs be the same as or different from those in non-HCAs?
    1. INGAA commented that repair schedules outside HCAs should be
similar to those in HCAs but should allow for more scheduling latitude.
This comment was supported by comments received from many of its
operator members. They also noted that adding requirements to repair
non-HCA anomalies would significantly increase the number of required
repairs and that an inappropriate requirement for rapid response would
dilute the focus on risk-significant repairs. INGAA suggested that
repair schedules should be more a function of anomaly growth rates than
location along the pipeline. INGAA further suggested that
inappropriately rapid response schedules would increase risk;
experience shows that most anomalies that have been found and repaired
are old, do not require a rapid response, and that mandating rapid
response to such anomalies would necessarily dilute other safety
activities.
    2. Texas Pipeline Association and Texas Oil & Gas Association
expressed doubt that significant risk reduction would result from
shortened repair schedules, given the logistics and related work
involved in repairs.
    3. GPTC, Nicor, and an anonymous commenter objected to applying HCA
repair criteria outside HCAs. They believe that the costs for such an
approach are not justified and non-HCA anomalies are appropriately
dealt with under operations and maintenance requirements and
procedures.
    4. Ameren Illinois, Paiute, and Southwest Gas agreed that
prescriptive repair schedules are not needed outside HCAs. They
expressed a belief that operators must have scheduling flexibility to
accommodate the needs of their operations.
    5. MidAmerican suggested that immediate repair criteria be applied
both in HCAs and outside HCAs, but that other criteria be limited to
HCAs.
    6. Northern Natural Gas suggested that PHMSA should require
operators to determine response schedules for non-HCA anomalies as part
of this rulemaking.
    7. Iowa Association of Municipal Utilities commented that the
existing requirements are sufficient for the small, low-stress
transmission pipelines operated by its members.
    8. California Public Utilities Commission commented that all method

1 HCA locations should be subject to HCA repair criteria.
    9. MidAmerican, Paiute, and Southwest Gas commented that shortened
response schedules will not reduce risk. These operators suggested that
response times should be based on risk rather than being established
arbitrarily.
Response to Question C.4 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA
believes repair schedules outside HCAs should be similar to those in
HCAs but should allow for more scheduling latitude. PHMSA proposes to
establish three timeframes for remediating defects in non-HCA areas:
Immediate repair conditions, 2-year repair conditions (rather than one-
year for HCAs), and monitored conditions. These changes will ensure the
prompt remediation of anomalous conditions on all gas pipeline
segments, commensurate with risk, while allowing operators to allocate
their resources to those areas that present a higher risk.
    C.5. Have ILI tool capability advances resulted in a need to update
the ``dent with metal loss'' repair criteria?
    1. INGAA commented that ILI tool capabilities have improved to the
point where it is appropriate to revise the dent-with-metal loss
criterion. This comment was supported by comments received from many of
its operator members. INGAA suggested that Section 851.4(f) of ASME/
ANSI B31.8 provides appropriate guidance in this area.
    2. AGA suggested that it would be appropriate to eliminate the
immediate response criterion for ``dent with metal loss.'' This comment
was supported by comments received from many of its operator members.
They commented that industry experience has shown that many dents do
not require immediate repair.
    3. Texas Pipeline Association, Texas Oil & Gas Association,
MidAmerican, Paiute, Southwest Gas, and Atmos supported revising this
criterion. These commenters noted that improvements in ILI allow better
distinction between a gouge and corrosion wall loss. MidAmerican
further commented that there are problems with implementing Sec.
192.933 as written.
    4. Northern Natural Gas stated that it would support treating these
anomalies as mechanical damage, and suggested that this would simplify
the regulations.
    5. Ameren Illinois suggested further study of this proposal taking
into account current ILI technology.
    6. Accufacts and an anonymous commenter opposed changes to this
criterion. These commenters suggested that ILI is still not adequate to
determine reliably the time to failure of this compound threat.
    7. GPTC and Nicor suggested that PHMSA consider updating the Dent
Study technical report \35\ that discusses reliability and application
of ILI.
---------------------------------------------------------------------------

    \35\ Baker and Kiefner & Associates, ``Dent Study Technical
Report,'' (November 2004, OPS TTO Number 10, available at http://primis.phmsa.dot.gov/gasimp/techreports.htm).
---------------------------------------------------------------------------

Response to Question C.5 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA
is not proposing to update the dent-with-metal-loss criterion at this
time. PHMSA will continue to evaluate this criterion, including
consideration of additional research to better define the repair
criteria for this specific type of defect.
    C.6. How do operators currently treat assessment tool uncertainties
when comparing assessment results to repair criteria? Should PHMSA
adopt explicit voluntary standards to account for the known accuracy of
in-line inspection tools when comparing in-line inspection tool data
with the repair criteria? Should PHMSA develop voluntary assessment
standards or prescribe ILI assessment standards including wall loss
detection threshold depth detection, probability of detection, and
sizing accuracy standards that are consistent for all ILI vendors and
operators? Should PHMSA prescribe methods for validation of ILI tool
performance such as validation excavations, analysis of as-found versus
as-predicted defect dimensions? Should PHMSA prescribe appropriate
assessment methods for pipeline integrity threats?
    1. INGAA, supported by many of its member companies, reported that
operators use many methods to accommodate ILI uncertainties, not simply
adding tool tolerance to results. INGAA suggested API-1163, In-line
Inspection Systems Qualification Standard, as an appropriate guide.
INGAA noted this standard is non-prescriptive; INGAA expressed its
belief prescriptive standards would stifle innovation. INGAA also
reported that ASME has plans to update its standard on ``Gas
Transmission and Distribution Piping Systems,'' ASME/ANSI B31.8S,
regarding treatment of uncertainties based on the results of Pipeline
Research Council International (PRCI) research that was underway at the
time comments were submitted.
    2. AGA and a number of pipeline operators suggested that tool
tolerances should be added to ILI results.
    3. Texas Pipeline Association, Texas Oil & Gas Association, and
Atmos reported their understanding that most operators follow ASME/ANSI
B31.8S as a guide.
    4. Northern Natural Gas and Kern River expressed their conclusion
that PHMSA's Gas Integrity Management Program Frequently Asked Question
FAQ-68 provides sufficient guidance on the treatment of uncertainties
(FAQs can be viewed at http://primis.phmsa.dot.gov/gasimp/faqs.htm).
They noted that technology is developing rapidly in this area, which
they imply is a reason not to impose prescriptive requirements.
    5. Texas Pipeline Association and Texas Oil & Gas Association
agreed that prescriptive requirements should not be imposed, because
the rapidly-developing technology would soon render them obsolete.
    6. GPTC, Nicor, MidAmerican, and Atmos argued that prescriptive
methods for validating tool performance are not an appropriate subject
for regulation.
    7. Ameren Illinois commented that it sees no technical
justification for establishing requirements in this area.
    8. Accufacts suggested that PHMSA specify minimum standards for ILI
validation, including specifying a required number of digs. Alaska
Department of Natural Resources and California Public Utilities
Commission took a similar stance, all arguing that standards assure
public confidence and consistency of results.
    9. A private citizen commented that voluntary standards are not
sufficient because they cannot be enforced.
    10. An anonymous commenter recommended against adopting
requirements for treatment of inaccuracies. The commenter opined that
operators are doing better in this area, contending that smaller
operators, in particular, needed time to learn. The commenter suggested
that specific rules would set many operators back.
    11. INGAA and many of its pipeline operators commented that
incorporating standards into part 192 that compete with industry
standards would be counterproductive. INGAA noted that API-1163, API-
579-1, Fitness-for-Service, and ASNT ILI-PQ, In-Line Inspection
Personnel Qualification and Certification Standard, are already in wide
use and contended specifying standards in the regulations would stifle
further development.
    12. GPTC and Nicor agreed with INGAA, noting that the regulatory
approval process cannot keep up with technological development.
    13. Northern Natural Gas recommended that PHMSA not adopt standards
for addressing ILI inaccuracies, contending the many

different tools currently in use would make this impractical.
    14. MidAmerican reported its belief that operators have sufficient
incentive to work with ILI vendors to assure appropriate validation of
ILI results.
    15. Paiute and Southwest Gas argued against adoption of regulatory
standards to treat ILI uncertainties, noting that this subject is
already addressed in ASME/ANSI B31.8S.
    16. AGA, supported by a number of its member companies, suggested
that PHMSA should not prescribe IM methods, noting that operators have
demonstrated the ability to conduct assessments without them.
    17. Accufacts, Alaska Natural Gas Development Authority, and
California Public Utilities Commission argued for requirements
prescribing assessment methods for various threats. These commenters
suggested that such requirements would be a bridge to better risk
management strategies and contended that there is currently an over-
reliance on direct assessment.
Response to Question C.6 Comments
    PHMSA appreciates the information provided by the commenters. The
majority of comments do not support adopting explicit standards or
analytical methodologies to account for the known accuracy of in-line
inspection tools. PHMSA concurs that prescriptive rules to account for
the accuracy of in-line inspection tools is not practical, however it
is beneficial to all to clarify PHMSA's expectations with respect to
current performance-based regulations in this area which specify that
internal inspection may be used to identify and evaluate potential
pipeline threats. Therefore, PHMSA proposes to add detailed
performance-based rule language to require that operators using ILI
must explicitly consider uncertainties in reported results (including
tool tolerance, anomaly findings, and unity chart plots or equivalent
for determining uncertainties) in identifying anomalies. While ASME/
ANSI B31.8S discusses uncertainties, PHMSA believes it will improve the
visibility and emphasis on this important issue to explicitly address
uncertainties in the rule text.
    C.7. Should PHMSA adopt standards for conducting in-line
inspections using ``smart pigs,'' the qualification of persons
interpreting in-line inspection data, the review of ILI results
including the integration of other data sources in interpreting ILI
results, and/or the quality and accuracy of in-line inspection tool
performance, to gain a greater level of assurance that injurious
pipeline defects are discovered? Should these standards be voluntary or
adopted as requirements?
    1. AGA and its pipeline operator members argued against the
adoption of standards. AGA commented that voluntary use has proven to
be sufficient and expressed its position that consensus standards
should not be adopted into regulations until widespread experience has
been gained with their use. AGA contended that premature adoption would
stifle technological innovation.
    2. INGAA and many of its members commented that PHMSA's process for
review and adoption of standards must be streamlined if existing
consensus standards are incorporated into regulations. Such
improvements, INGAA contended, would assure that standard improvements
are adopted without delay.
    3. An anonymous commenter, GPTC, and Nicor cited similar concerns
in suggesting that standards not be adopted into regulations,
contending that the rulemaking process cannot keep up with
technological change.
    4. Texas Pipeline Association and Texas Oil & Gas Association
objected to the adoption of ILI standards in regulations, contending
that voluntary use is more appropriate.
    5. MidAmerican commented that operator qualification requirements
should be applied to ILI, as this would provide higher assurance of
defect discovery. Beyond this, however, MidAmerican contended that the
use of consensus standards should remain voluntary, as this allows the
operator to select those standards most appropriate to its
circumstances.
    6. Paiute and Southwest Gas objected to the incorporation of ILI
standards into regulations. The companies expressed a belief that there
is no technical basis for doing so. They commented that the question,
as posed in the ANPRM, implies that anomalies are not now being found
and contended that there is no evidence to support this implication.
    7. A private citizen, Thomas Lael, and Alaska Department of Natural
Resources commented that PHMSA should require operators to meet
specified standards. Mr. Lael referred to an incident that occurred
following a pipeline assessment conducted in Ohio in 2011; Mr. Lael
contended that the reasons the incident cause was not identified by the
assessment are unknown to the public.
    8. Pipeline Safety Trust commented that PHMSA should assure
assessment tools are capable and are used properly.
    9. The NTSB recommended that PHMSA require all pipelines to be made
piggable, giving priority to older lines, citing their recommendation
P-11-17.
Response to Question C.7 Comments
    PHMSA appreciates the information provided by the commenters. The
majority of industry comments do not support the incorporation of ILI
standards into regulations. However, based on the information presented
below, PHMSA has concluded that it is prudent to propose incorporating
available consensus ILI standards into the regulations. The current
pipeline safety regulations for integrity management of segments in
HCAs contained in 49 CFR 192.921 and 192.937 require that operators
assess the material condition of pipelines in certain circumstances and
allow use of in-line inspection tools for these assessments. PHMSA
proposes to incorporate similar requirements for non-HCA pipe segments
in Sec.  192.710. Operators are required to follow the requirements of
ASME/ANSI B31.8S in selecting the appropriate ILI tools. However, ASME
B31.8S provides only limited guidance for conducting ILI assessments.
At the time the integrity management rules were promulgated, there was
no consensus industry standard that addressed performance of ILI. Three
related standards have since been published: API STD 1163-2005, NACE
SP0102-2010, and ANSI/ASNT ILI-PQ-2010. API-1163 serves as an umbrella
document to be used with and complement the NACE and ASNT standards.
These three standards have enabled service providers and pipeline
operators to provide processes that will qualify the equipment, people,
processes, and software utilized in the in-line inspection industry.
The incorporation of these standards into pipeline safety regulations
developed through best practices of the industry based on the
experience of numerous operators will promote high quality and more
consistent assessment practices. Therefore, PHMSA is proposing to
incorporate these industry standards into the regulations to provide
clearer guidance for conducting integrity assessments with in-line
inspection. PHMSA will continue to evaluate the need for additional
guidance for conducting integrity assessments.
    C.8. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
     The potential costs of modifying the existing regulatory
requirements

pursuant to the commenter's suggestions.
     The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the
existing regulatory requirements.
     The potential environmental impacts of modifying the
existing regulatory requirements.
    No comments were received in response to this question.

D. Improving the Collection, Validation, and Integration of Pipeline
Data

    The ANPRM requested comments regarding whether more prescriptive
requirements for collecting, validating, integrating and reporting
pipeline data are necessary. The current IM regulations require that
gas transmission pipeline operators gather and integrate existing data
and information concerning their entire pipeline that could be relevant
to pipeline segments in HCAs (Sec.  192.917(b)). Operators are then
required to use this information in a risk assessment of the HCA
segments (Sec.  192.917(c)) that must subsequently be used to determine
whether additional preventive and mitigative measures are needed (Sec.
192.935) and to define the intervals at which IM reassessments must be
performed (Sec.  192.939). Operators' risk analyses and conclusions can
only be as good as the information used to perform the analyses. On
August 30, 2011, after the ANPRM was issued, the NTSB adopted its
report on the gas pipeline accident that occurred on September 9, 2010,
in San Bruno, California. Results from the NTSB investigation indicate
that the pipeline operator's records regarding the physical attributes
of the pipe segments involved in the incident were erroneous. NTSB
recommendation P-11-19 recommended that PHMSA require IM programs be
assessed to assure that they are based on clear and meaningful metrics.
In addition, Section 23 of the Act requires verification to ensure that
records accurately reflect the physical and operational characteristics
of pipelines. PHMSA issued an Advisory Bulletin (76 FR 1504; January
10, 2011) on this issue. The following are general comments received
related to the topic as well as comments related to the specific
questions:
General Comments for Topic D
    1. INGAA reported that it is presently working on data integration
guidelines. INGAA cautioned that requirements in this area can be very
costly, since they often necessitate redesign of existing data
management systems.
    2. AGA commented that no records requirements would have prevented
the San Bruno accident, and stated that verifying records does not
assure completeness, as unknown parameters remain unknown.
    3. A private citizen suggested that PHMSA should require operators
to identify segments where they lack knowledge of critical parameters.
The commenter suggested that this could facilitate emergency
communications and help prioritize pipe replacement programs.
Response to General Comments for Topic D
    PHMSA appreciates the information provided by the commenters. PHMSA
is proposing to clarify requirements for collecting, validating, and
integrating data. The current rule invokes ASME/ANSI B31.8S
requirements for data collection and integration. To provide greater
visibility and emphasis on this important aspect of integrity
management, PHMSA is proposing to place these requirements in the rule
text, rather than incorporating ASME/ANSI B31.8S by reference. The
proposed requirements clarify PHMSA's expectations regarding the
minimum list of data an operator must collect, and also includes
performance-based language that requires the operator to validate data
it will use to make integrity-related decisions, and require operators
to integrate all such data in a way that improves the analysis. The
proposed rule would also require operators to use reliable, objective
data to the maximum extent practical. To the degree that subjective
data from subject matter experts must be used, PHMSA proposes to
require that an operator's program include specific integrity
assessment and findings data for the threat features to compensate for
subject matter expert (SME) bias. The importance of these aspects of
integrity management was emphasized by both the NTSB (Recommendation P-
11-19) and Congress (The Act, Section 11(a)(4)).
Comments Submitted for Questions in Topic D
    D.1. What practices are now used to acquire, integrate and validate
data (e.g., review of mill inspection reports, hydrostatic tests
reports, pipe leaks and rupture reports) concerning pipelines? Are
practices in place, such as excavations of the pipeline, to validate
data?
    1. INGAA reported that its members have completed a concerted
effort to validate pipeline historical records pursuant to PHMSA
Advisory Bulletin 11-01 (issued January 10, 2011).
    2. Texas Pipeline Association and Texas Oil & Gas Association
commented that there is no great benefit to be gained from adding a
verification requirement for historical data to the regulations. The
associations believe that most operators will correct their records
when they become aware of errors regardless of how the erroneous
information is discovered. The associations suggested that there could
be value in validating databases against original records, since an
underlying problem of the San Bruno accident was errors in transferring
original records into a database.
    3. Ameren Illinois reported that it collects data on exposed pipe
in accordance with Sec. Sec.  192.459 and 192.475.
    4. Northern Natural Gas and Kern River reported that their primary
integration tool is integrity alignment sheets, which show the class
location, profile, aerial photography, alignment and structure data,
in-line inspection results, other integrity data, i.e., close-interval
survey or pressure test results and pipe, coating and appurtenance
data. Data is validated as opportunities arise.
    5. Paiute and Southwest Gas reported that they confirm the location
and properties of its pipeline as opportunities arise; more data are
collected as assessments are conducted.
    6. California Public Utilities Commission suggested that operators
be explicitly required to obtain all historical records and that there
be an officer statement that a thorough search for all records has been
conducted.
    7. A private citizen commented on the lack of some historical data,
implying that operators should be required to validate their knowledge
of older pipelines.
    8. An anonymous commenter stated that older data is typically not
validated.
    9. INGAA and AGA reported that pipeline operators take advantage of
exposed pipe to collect and validate data on in-service pipelines. This
includes excavations for ILI validation, those conducted as part of
direct assessment, and removed or replaced pipelines. A number of
pipeline operators provided comments supporting the comments of each
association.
    10. GPTC and Nicor suggested that excavations not be required for
the sole purpose of validating data, contending that the risks posed by
such a requirement would outweigh any benefit obtained.

    11. MidAmerican reported that it validates information when
pipeline is excavated and through its routine practices.
Response to Question D.1 Comments
    PHMSA appreciates the information provided by the commenters. See
response to question D.4.
    D.2. Do operators typically collect data when the pipeline is
exposed for maintenance or other reasons to validate information in
their records? If discrepancies are found, are investigations conducted
to determine the extent of record errors? Should these actions be
required, especially for HCA segments?
    1. AGA, Paiute, and Southwest Gas reported that operators use
exposed pipe as an opportunity to collect information. AGA further
suggested, however, that PHMSA should not draft a rule governing these
practices. AGA contended the circumstances of pipe exposures vary too
much to be addressed by a regulatory requirement. AGA expressed its
conclusion that the requirements in Sec.  192.605(b)(3) provide
adequate guidance and that section 23 of the Pipeline Safety,
Regulatory Certainty, and Job Creation Act of 2011 provides additional
guidance. AGA noted that operators investigate identified inaccuracies
and errors. A number of other pipeline operators provided comments
supporting AGA's comments.
    2. Texas Pipeline Association, Texas Oil & Gas Association, Atmos,
MidAmerican, and Ameren Illinois reported that operators typically
collect information on pipe type and condition, but not on historical
information and pipe specifications. They commented that collecting
this information would require additional testing and pose operational
impacts.
    3. Iowa Utilities Board and Iowa Association of Municipal Utilities
commented that any new requirement should be limited to collecting
readily obtainable data, principally that which can be determined
visually. They suggested that the data elements in ANPRM questions D.1
and D.3 go beyond what can readily be observed or obtained and it would
be impractical to require this data to be collected during pipe
exposures.
    4. California Public Utilities Commission commented that any new
requirements to collect data during pipe exposures should address all
instances of exposure rather than be limited to HCAs, noting that non-
HCA segments can become HCA segments due to changes in land use near
the pipeline.
    5. Thomas Lael and Alaska Department of Natural Resources commented
that operators should be required to collect specific data during pipe
exposures. These commenters contended that not all operators currently
collect available data during pipe exposures.
    6. MidAmerican, Paiute, and Southwest Gas commented that no new
requirements are needed because the requirements in part 192 and
guidance in ASME/ANSI B31.8S are sufficient.
    7. An anonymous commenter suggested that operators be required to
collect data if they do not have enough information to analyze the
risks of the pipeline segment.
Response to Question D.2 Comments
    PHMSA appreciates the information provided by the commenters. The
expanded rule language does not impose new requirements for collecting
specific data during pipe exposures, but the response to question D.4
discusses proposed changes to collection and validation practices to
improve data integration and risk assessment practices.
    D.3. Do operators try to verify data on pipe, pipe seam type, pipe
mechanical and chemical properties, mill inspection reports,
hydrostatic tests reports, coating type and condition, pipe leaks and
ruptures, and operations and maintenance (O&M) records on a periodic
basis? Are practices in place to validate data, such as excavation and
in situ examinations of the pipeline? If so, what are these practices?
    1. AGA, GPTC, Nicor, Paiute, and Southwest Gas reported that
operators do try to verify information but that operator practices are
too numerous to list in response to this general question. They
contended that the requirements for external corrosion control in Sec.
192.459 and for internal corrosion control in Sec.  192.475 and the
guidance in Advisory Bulletin 11-01 are sufficient and no new
requirements are needed. A number of other pipeline operators provided
comments supporting AGA's comments.
    2. INGAA, supported by many of its pipeline operator members,
commented that there are limited, if any, methods to determine
accurately mechanical properties of pipe that is in situ. INGAA's
comments listed a number of methods that can be used to obtain
approximate values for some pipe characteristics, such as steel
hardness and yield strength.
    3. Texas Pipeline Association and Texas Oil & Gas Association
commented that operators do not validate mill data after initial
construction.
    4. Ameren Illinois reported that data review and correction is a
normal part of the business of pipeline operation. Ameren commented
that additional work in this area is likely to result from Advisory
Bulletin 11-01.
    5. Northern Natural Gas reported that data correction occurs when a
discrepancy is identified. Northern also noted that it has added data
to its risk model over time, principally related to determination of
the potential consequences of a pipeline accident.
    6. MidAmerican commented that operators validate pipeline
information periodically.
    7. California Public Utilities Commission reported that California
pipeline operators have begun validating pipeline data since the San
Bruno accident. CPUC commented that operators should determine pipeline
specifications for all exposed facilities and use them to validate
their records.
    8. Paiute and Southwest Gas reported that it is their practice to
obtain pipeline data before an integrity management excavation and then
to validate that information in the field.
    9. MidAmerican reported that it uses a geospatial database as its
principal tool for collecting and validating pipeline information.
    10. An anonymous commenter suggested that pipeline operators do not
routinely collect information to validate their databases during
pipeline excavations.
Response to Question D.3 Comments
    PHMSA appreciates the information provided by the commenters. See
response to question D.4.
    D.4. Should PHMSA make current requirements more prescriptive so
operators will strengthen their collection and validation practices
necessary to implement significantly improved data integration and risk
assessment practices?
    1. INGAA, GPTC, Nicor, Ameren Illinois, MidAmerican, Paiute and
Southwest Gas commented that additional prescriptive requirements are
not needed. These commenters suggested that Advisory Bulletin ADB-11-
01, subpart O of part 192, and ASME/ANSI B31.8S are sufficient to
govern these practices. INGAA added requirements for data validation
during excavations could introduce workplace hazards that would
outweigh any benefit to be gained. In the event PHMSA proceeds to
propose new requirements, INGAA requested they be limited to a
reasonable process and allow assumptions to be made to fill information
gaps, suggesting this would be a more cost-effective approach than

rigorous requirements to collect and validate all information. A number
of other pipeline operators provided comments supporting INGAA's
comments.
    2. AGA, supported by a number of its pipeline operator members,
commented that there is no evidence to support a need for more
prescriptive requirements leading to better data collection or
validation and, therefore, no such requirements are needed.
    3. Pipeline Safety Trust, NAPSR, California Public Utilities
Commission, and Commissioners of Wyoming County, Pennsylvania,
commented that requirements for data collection, validation, and use
should be more prescriptive. These commenters noted that the
investigation of the San Bruno accident identified at least one
pipeline operator was not doing an adequate job of data validation.
They noted that NTSB recommendations P-11-18 and P-11-19 apply to this
topic. NAPSR specifically requested that new requirements specify
precise inspection criteria.
    4. Texas Pipeline Association and Texas Oil & Gas Association
suggested that there is no value in periodic validation of pipeline
data and new requirements are not needed in this area. Northern Natural
Gas agreed, noting that pipeline data does not change over time, and
relevant data that is subject to change, is that data needed to
evaluate the consequences of potential pipeline accidents.
    5. Accufacts commented that more specific criteria, including
minimum data requirements, are needed for record retention. Accufacts
noted that integrity management is data-based and that too many
operators claim that data is lost or cannot be found.
    6. Alaska Department of Natural Resources suggested that data
integration should be required in interpreting ILI results.
    7. An anonymous commenter suggested that specific requirements are
not needed in this area, contending that most data has been validated
through normal operator practices.
    8. A private citizen suggested that PHMSA require pipeline
operators to post all records for access by state and local government
officials, PHMSA, and the media. The commenter suggested such a
``sunshine'' provision would improve recordkeeping, even if no one ever
examines the posted records.
Response to Question D.4 Comments
    PHMSA appreciates the information provided by the commenters in
response to questions D.1 through D.4. Commenters disagreed on the need
and benefit of making current requirements more prescriptive so
operators will strengthen their collection and validation practices.
PHMSA believes enhancing regulations in this area is an important
element of good integrity management practices. On July 21, 2011, in
response to the San Bruno incident, PHMSA sponsored a public workshop
on risk assessment and related data analysis and recordkeeping issues
to seek input from stakeholders. Based in part on the input received at
this workshop, and the information submitted in response to the ANPRM,
PHMSA proposes to clarify the performance-based requirements for
collecting, validating, and integrating pipeline data by adding
specificity to the data integration language, establishing a number of
pipeline attributes that must be included in these analyses, explicitly
requiring that operators integrate analyzed information, and ensuring
data is reliable. The rule also requires operators to use validated,
objective data to the maximum extent practical. PHMSA also understands
that objective sources such as as--built drawings, alignment sheets,
material specifications, and design, construction, inspection, testing,
maintenance, manufacturer, or other related documents are not always
available or obtainable. To the degree that subjective data from
subject matter experts must be used, PHMSA proposes to require that an
operator's program include specific features to compensate for subject
matter expert bias. PHMSA believes that these proposed changes would
not impose new requirements or more prescriptive requirements, but
clarifies the intent of the regulation. However, PHMSA requests public
comment on whether and the extent to which this proposal may change
behavior.
    D.5. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
     The potential costs of modifying the existing regulatory
requirements pursuant to the commenter's suggestions.
     The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the
existing regulatory requirements.
     The potential environmental impacts of modifying the
existing regulatory requirements.

    No comments were received in response to this question.

E. Making Requirements Related to the Nature and Application of Risk
Models More Prescriptive

    The ANPRM requested comments regarding whether requirements related
to the nature and application of risk models should be made more
prescriptive to improve the usefulness of these analyses in controlling
risks from pipelines. Current regulations require that gas transmission
pipeline operators perform risk analyses of their pipelines and use
these analyses to make certain decisions to assure the integrity of
their pipeline and to enhance protection against the consequences of
potential incidents. The regulations do not prescribe the type of risk
analysis nor do they impose any requirements regarding its breadth and
scope, other than requiring that it consider the entire pipeline.
PHMSA's experience in inspecting operator compliance with IM
requirements has identified that most pipeline operators use a relative
index-model approach to performing their risk assessments and that
there is a wide range in scope and quality of the resulting analyses.
It is not clear that all of the observed risk analyses can support
robust decision-making and management of the pipeline risk. The
following are general comments received related to the topic as well as
comments related to the specific questions:
General Comments for Topic E
    1. INGAA and Chevron commented that continuing the performance-
based regulatory approach, exemplified by integrity management, is
critically important to pipeline safety. They suggested that
prescriptive management systems are task oriented, do not adjust easily
to new information or knowledge, inhibit innovation, and could thwart
safety improvements. A number of other pipeline operators provided
comments supporting INGAA's comments.
    2. Accufacts commented that risk management approaches permitted in
IM need additional prescriptive measures to clarify strengths and
weaknesses and to assure compliance. Public perception resulting from
the number of serious incidents is that current risk analysis and risk
management approaches are not sufficient. The impression is that risk
management is being used to justify unwise lowest cost decisions rather
than being used as a tool to avoid failure. Accufacts further suggested
that interactive threats need to be addressed by prescriptive
requirements in safety

regulations because operators may be under the illusion that some of
the more serious threats are stable after almost 10 years of IM
regulation.
    3. Oleksa and Associates suggested that it would be statistically
more valid for many (perhaps most) operators for PHMSA to perform
continual evaluation and assessment using established performance
measures along with data submitted by operators on annual, incident,
and safety-related condition reports, and then to promulgate more
prescriptive regulations resulting from that assessment. Oleksa
suggested that it may be time to re-evaluate the overall concept of
integrity management to determine whether it makes sense for each
operator to make assessments that might be more valid if made on a
national level. Oleksa also stated that there should be a concerted
effort in promulgating any new regulations towards making the
regulations simple enough so that they can be understood relatively
easily.
    4. TransCanada commented that PHMSA's IM regulations should provide
explicit metrics for operators to demonstrate safety decision processes
without restricting the opportunity to use more accurate and advanced
methods. TransCanada said that any efforts to make risk models more
prescriptive should focus on process elements while providing operators
the flexibility to build processes which recognize the unique
characteristics of their pipeline systems. The company also opined that
issuing more detailed guidelines on specific integrity management plan
elements would enhance the current, performance-based approach and
generate additional benefits that the public and operators desire.
    5. Dominion East Ohio Gas opposed making requirements for risk
models more prescriptive. Like INGAA, they that noted prescriptive
management systems are task oriented and do not adjust easily to new
information or knowledge. They inhibit innovation and could thwart
safety improvements.
    6. NAPSR strongly urged PHMSA to make the nature and application of
risk models more prescriptive. NAPSR commented that PHMSA has not
provided any data that supports the theory that risk modeling provides
a stronger safety environment and contended that, in fact, the opposite
may be occurring.
    7. A private citizen suggested that PHMSA correlate the quality of
an operator's risk model with the number of enforcement actions against
that operator.
    8. A private citizen suggested that risk analysis requirements
should remain flexible, commenting that prescribed methods or
requirements could mask operator-specific issues.
Response to General Comments for Topic E
    PHMSA appreciates the information provided by the commenters. PHMSA
agrees that prescriptive rules for risk assessments are not appropriate
because one-size-fits-all regulations would not be effective for such a
diverse industry. However, PHMSA does believe that operator risk models
and risk assessments should have substantially improved since the
initial framework programs established nearly 10 years ago. While
simple index or relative (qualitative) ranking models were useful to
prioritize HCA segments for purposes of scheduling integrity baseline
assessments, those models have limited utility to perform the analyses
needed to better understand pipeline risks, better understand failure
mechanisms (especially for interacting threats), or to identify
effective preventive and mitigative measures. PHMSA is proposing to
further clarify its expectations for this aspect of the performance-
based regulations to further improve pipeline safety. On July 21, 2011,
PHMSA sponsored a public workshop on risk assessment to seek input from
stakeholders. PHMSA has evaluated the input it received at this
workshop. PHMSA proposes to clarify the risk assessment aspects of the
IM rule to explicitly articulate functional requirements and to assure
that risk assessments are adequate to: (1) Evaluate the effects of
interacting threats, (2) determine intervals for continual integrity
reassessments, (3) determine additional preventive and mitigative
measures needed, (4) analyze how a potential failure could affect HCAs,
including the consequences of the entire worst-case incident scenario
from initial failure to incident termination, (5) identify the
contribution to risk of each risk factor, or each unique combination of
risk factors that interact or simultaneously contribute to risk at a
common location, (6) account and compensate for uncertainties in the
model and the data used in the risk assessment, and (7) evaluate
predicted risk reduction associated with preventive and mitigative
measures. In addition, in response to NTSB recommendation P-11-18,
PHMSA proposes to require that operators validate their risk models in
light of incident, leak, and failure history and other historical
information. PHMSA also proposes to expand the list of example
preventive and mitigative measures to include the following items:
establish and implement adequate operations and maintenance processes
that could affect safety; establish and deploy adequate resources for
successful execution of activities, processes, and systems associated
with operations, maintenance, preventive measures, mitigative measures,
and managing pipeline integrity; and correct the root cause of past
incidents to prevent recurrence.
    In response to Oleksa's comments, PHMSA is addressing performance
measures outside of this rulemaking. Performance measures will be
addressed separately in response to NTSB safety recommendations P-11-18
and P-11-19.
Comments Submitted for Questions in Topic E
    E.1. Should PHMSA either strengthen requirements on the functions
risk models must perform or mandate use of a particular risk model for
pipeline risk analyses? If so, how and which model?
    1. INGAA, AGA, and many pipeline operators reported that they do
not believe there is a pipeline safety benefit for PHMSA to
``strengthen'' or revise the requirements on functions that risk models
must perform or in mandating the use of specific risk models. These
commenters noted that there is a tremendous amount of diversity in the
pipeline systems of individual operators and operators must have the
flexibility to select the risk model that best supports their systems.
    2. GPTC commented that there is no `one-size-fits-all' risk model.
GPTC further commented PHMSA has offered no data supporting the need to
strengthen requirements or mandate a particular risk model.
    3. Kern River noted that differences exist between pipeline
operators on how much detail is needed in their risk assessment models.
The specific factors and required risk model complexity will differ for
each pipeline company based on its active threats, the preventive and
mitigative measures employed, its data acquisition methods and the
amount of required data.
    4. MidAmerican commented that no change is needed to requirements
concerning risk models. MidAmerican noted that ASME/ANSI B31.8S
provides extremely detailed requirements in this area, and suggested
that operators should have the freedom to choose the risk model best
suited to their operation. Northern Natural Gas agreed, noting that
there are large differences within the industry on the complexity of
the risk assessment models used based on the

pipeline age and configuration, threats, and data available.
    5. Paiute and Southwest Gas opposed more restrictive requirements
for risk modeling. They noted that operators have a decade of
experience working with IM and therefore, should have the flexibility
to choose the risk model that best suits their system.
    6. Accufacts commented that this is an area that needs more
prescriptive requirements. Accufacts questioned whether the current
approach of reliance on risk modeling is even appropriate. They stated
that there appears to be a disconnect between the use of risk models
and risk analysis with pipeline operation and the ability of regulators
to apply and enforce the approach.
    7. TransCanada noted that mandating the use of a specific risk
model may result in a more uniform approach across the industry, but
may also force operators to abandon their existing risk models,
including the improvements made to them based on 10 years of integrity
management experience. This would not appear to advance risk modeling
and might even be counterproductive.
    8. WKM Consultancy commented that mandating a specific risk
assessment model would not be a beneficial addition to regulations.
Such a mandate would stifle creativity and require extensive
definitions and documentation of that methodology. A mandated model
would introduce a prescriptive element with substantial ``overhead''
related to the maintenance of the model's documentation by the
regulators. They suggested that a better solution would be to develop
guidelines of essential ingredients necessary in any pipeline risk
assessment.
    9. An anonymous commenter opposed requiring the use of a specific
risk model, suggesting that operators should use models with which they
are comfortable. The commenter did suggest that PHMSA strengthen
requirements concerning the use of risk models for purposes other than
risk-ranking segments, expressing a belief that most operators are
using their models only for that purpose.
    10. California Public Utilities Commission recommended that PHMSA
require statistical data be maintained and used to support the
weightings assigned by risk models to various threats.
Response to Question E.1 Comments
    PHMSA appreciates the information provided by the commenters. A
large number of comments do not support adding a requirement for a
specific risk assessment model or for strengthening or revising the
required functions that risk models must perform. PHMSA agrees that
prescribing the use of particular risk assessment models is not
appropriate for such a diverse industry, and notes that relative index
models have been successfully used to rank pipelines to prioritize
baseline assessments. However, PHMSA believes that the integrity
management rule anticipates that operators would continually improve
their risk assessment processes and that there are specific risk
assessment attributes related to the nature and application of risk
models that need clarification. Such attributes and shortcomings were
discussed at the ``Improving Pipeline Risk Assessments and
Recordkeeping'' workshop with stakeholders, held on July 21, 2011.
    PHMSA proposes to articulate clear functional requirements, in
performance-based terms, for risk assessment methods used by operators.
While PHMSA does not propose to prescribe the specific risk assessment
model operators must use, PHMSA does propose to clarify the
characteristics of a mature risk assessment program. These include: (1)
Identifying risk drivers; (2) evaluating interactive threats; (3)
assuring the use of traceable and verifiable information and data; (4)
accounting for uncertainties in the risk model and the data used; (5)
incorporating a root cause analysis of past incidents; (6) validating
the risk model in light of incident, leak and failure history and other
historical information; (7) using the risk assessment to establish
criteria for acceptable risk levels; and (8) determining what
additional preventive and mitigative measures are needed to achieve
risk reduction goals. PHMSA proposes to clarify that the risk
assessment method selected by the operator must be capable of
successfully performing these functions.
    E.2. It is PHMSA's understanding that existing risk models used by
pipeline operators generally evaluate the relative risk of different
segments of the operator's pipeline. PHMSA is seeking comment on
whether or not that is an accurate understanding. Are relative index
models sufficiently robust to support the decisions now required by the
regulation (e.g., evaluation of candidate preventive and mitigative
measures, and evaluation of interacting threats)?
    1. Industry commenters, including INGAA, AGA, Texas Pipeline
Association, Texas Oil & Gas Association, WKM Consultancy, and many
pipeline operators reported that PHMSA's understanding is correct and
that risk models in use generally evaluate the relative risk of
different segments of the operator's pipeline. AGA noted that operators
have selected and implemented the risk models that allowed them to
prioritize the covered segments for the baseline assessment and
subsequent reassessments and that this complied with the Pipeline
Safety Improvement Act of 2002.
    2. AGA, supported by a number of its pipeline operator members,
commented that risk models currently in use are sufficiently robust.
Ameren Illinois and GPTC expressed a similar belief.
    3. INGAA, supported by some of its members, noted that there is
room for improvement in the current practices of risk modeling. INGAA
reported that the industry has established committees to identify
advancements in risk modeling.
    4. WKM Consultancy commented that the more robust of the relative
risk index techniques are often capable of fulfilling some aspects of
IM risk management requirements such as prioritization, but that other
aspects of the risk management requirements are not well supported by
relative risk assessments. They suggested that some risk assessment
models in current use could benefit from application of more robust and
modern techniques.
    5. Kern River commented that a relative risk model is sufficiently
robust to support decisions on preventive and mitigative measures and
assessment intervals.
    6. MidAmerican reported that its risk model complies with ASME/ANSI
B31.8S and is sufficiently robust to support decisions that are not
specifically related to assessments. MidAmerican further stated that
its risk model produces results consistent with its subject matter
expert assessments of relative risk.
    7. Paiute and Southwest Gas reported their conclusion that their
risk models are robust and support the process of evaluation and
selection of preventive and mitigative measures.
    8. Texas Pipeline Association and Texas Oil & Gas Association noted
that all sources of information relative to the integrity of a
transmission pipeline segment and the identified risk should be used in
the selection of preventive and mitigative measures. Atmos agreed,
noting that preventive and mitigative measures for a given pipeline
segment are based on the identified threats.
    9. A private citizen suggested that consideration of system-wide
high risk (e.g., urban areas) should be required, contending relative
risk is not good enough when an entire system poses high risks.

Response to Question E.2 Comments
    PHMSA appreciates the information provided by the commenters.
Although a large number of comments contend risk models currently in
use are sufficiently robust, PHMSA believes that there are specific
risk assessment attributes not found in many of the simple index or
relative risk models currently in use. The July 21, 2011, workshop on
``Improving Pipeline Risk Assessments and Recordkeeping'' identified
several shortcomings in risk assessments conducted using qualitative,
index, or relative risk methodologies, and PHMSA is proposing to
clarify requirements to address these issues including the need for
better or more prescriptive guidance to address data gaps, data
integration, uncertainty, interacting threats, risk management, and
quantitative approaches instead of subjective or qualitative
approaches. The proposed regulation would require operators to conduct
risk assessments that effectively analyze the identified threats and
potential consequences of an incident for each HCA segment.
Additionally, the proposed regulation would require the risk assessment
to include evaluation of the effects of interacting threats, including
those threats and anomalous conditions not previously evaluated. It
should be further noted that the intent of the original IM rule is that
any risk assessment would consider system-wide risk.
    E.3. How, if at all, are existing models used to inform executive
management of existing risks?
    1. INGAA commented that operators should develop internal
communication plans and they should follow Section 10.3 of ASME/ANSI
B31.8S in doing so. AGA similarly noted that the methods used to
disseminate results of the risk evaluation to executive management are
operator specific and detailed in the operator's integrity management
plan. A number of pipeline operators provided comments supporting both
INGAA's and AGA's comments.
    2. Texas Pipeline Association and Texas Oil & Gas Association noted
that the results of risk modeling are usually used in conjunction with
assessment results to inform executive management of actions required
beyond normal repair, additional preventive and mitigative measures,
discussion of high risk pipelines, and progress in meeting assessment
goals.
    3. WKM Consultancy commented that operators are obliged to
communicate all aspects of integrity management to higher level
managers at regular intervals. They noted that all prudent operators
are very interested in risk management and results of risk modeling are
usually a centerpiece of discussion and decision-making.
    4. Ameren Illinois reported that its IM plan provides for informing
executive management of existing risks.
    5. Atmos reported that it provides executive management with
periodic updates on the status of its integrity management program.
During these updates, Atmos' executive management reviews baseline
assessment plans, assessment results, anomalies discovered and
mitigated, anomalies discovered and scheduled for repair, leading
causes of anomalies, and preventive and mitigative actions taken.
    6. Kern River noted that it provides its executive management with
reports describing integrity management program activities and results
and that the company engages the use of the risk model as an input to
financial planning and maintenance planning. MidAmerican also reported
that risk scores are used to support capital, operating and maintenance
expenditures to executive management.
    7. Northern Natural Gas reported that it provides executive
management with reports describing integrity management program
activities and results. Its executive management is engaged in the
process and the use of the risk model to prioritize projects.
    8. Paiute and Southwest Gas reported that integrity management
activities are discussed with executive management quarterly.
    9. An anonymous commenter suggested that operators generally do not
use risk models to inform executives, because they would have to
explain the models in order to do so.
Response to Question E.3 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA
understands that internal company processes for communication with
executive management are specific to each company. To strengthen the
application of risk assessment, PHMSA is proposing to clarify
requirements by providing more specific and detailed examples of the
kinds of preventive and mitigative measures operators should consider.
The proposed rulemaking would include the following specific examples
of preventive and mitigative measures that operators should consider:
Establish and implement adequate operations and maintenance processes;
establish and deploy adequate resources for successful execution of
activities, processes, and systems associated with operations,
maintenance, preventive measures, mitigative measures, and managing
pipeline integrity; and correct the root cause of past incidents to
prevent recurrence. The last item necessarily requires a robust root
cause analysis that identifies underlying programmatic or policy issues
that create or facilitate conditions or circumstances that ultimately
lead to pipeline failures.
    E.4. Can existing risk models be used to understand major
contributors to segment risk and support decisions regarding how to
manage these contributors? If so, how?
    1. INGAA and many of its pipeline operator members commented that
existing models can and do provide an understanding of segment risk
through threat identification, performing ``what if'' analyses, and
identifying preventive and mitigative measures that will reduce risk.
    2. AGA and GPTC noted that existing models selected by operators
are sufficiently robust to allow the integration of large volumes of
data and information to achieve a comprehensive overall risk evaluation
for their systems. These risk models allow an operator to understand
the specific threats associated with each pipeline segment and the
preventive and mitigative measures that would be most appropriate. A
number of pipeline operators provided comments supporting AGA's
comments.
    3. WKM Consultancy opined that currently used risk assessment
models generally can significantly improve the ability to manage risks.
They noted that a formal risk assessment provides the structure to
increase understanding, reduce subjectivity, and ensure that important
considerations are not overlooked.
    4. Atmos reported that its model can be used to generate a report
listing the significant variables contributing to a relatively higher
risk factor score, and that if a contributing variable can be
controlled, the risk model can support further actions to control the
variable.
    5. Ameren Illinois reported that it uses a robust risk model that
can integrate various risk factors in order to evaluate its system.
    6. Kern River and Northern Natural Gas commented that existing risk
models can be used to understand major contributors to segment risk and
support decisions regarding how to manage these contributors. By
identifying threat drivers in the risk results and analyzing the data
used by the model, integrity management personnel are able to reduce
risk through preventive and mitigative measures, improvements in data
quality, and shorter reassessment intervals.

    7. MidAmerican reported that its risk model is used to understand
major contributors to risk and to support decisions regarding how to
manage those contributors.
    8. Paiute and Southwest Gas reported that they conduct a review of
threat-specific indices to identify the major contributors to risk for
each threat.
    9. Texas Pipeline Association and Texas Oil & Gas Association noted
that risk modeling can be used to generate reports listing the
significant variables contributing to high risk scores.
    10. An anonymous commenter noted that risk models can serve these
functions and some operators use them in this way. The commenter opined
that most operators ``aren't there yet,'' and that operators who use
models for this purpose have more enthusiasm for integrity management
and more executive management support.
Response to Question E.4 Comments
    PHMSA appreciates the information provided by the commenters. The
majority of the comments suggest that current risk models provide an
adequate understanding of major contributors to risk. PHMSA believes it
is prudent to clarify the required attributes of risk assessment in
this area and proposes to include performance-based language to assure
that risk assessments adequately identify the contribution to risk of
each risk factor, or each unique combination of risk factors that
interact or simultaneously contribute to risk at a common location.
    E.5. How can risk models currently used by pipeline operators be
improved to assure usefulness for these purposes?
    1. INGAA noted that continuous improvement is required, and that
industry is working on improvements to ASME/ANSI B31.8S. AGA similarly
noted that risk models are periodically improved by operators by
integrating new data and the results of integrity assessments. A number
of pipeline operators provided comments supporting INGAA's and AGA's
comments.
    2. GPTC commented that new data and information are received on an
ongoing basis. This new data, and results of integrity assessments, are
reviewed, integrated, and added to risk models periodically.
    3. WKM Consultancy suggested that a limited amount of
standardization would be appropriate. They opined that this would
ensure that all risk assessments contain, at a minimum, a short list of
essential ingredients. For example, all assessments should produce a
profile showing changes in risk along a pipeline route.
    4. Ameren Illinois reported that its risk model allows for
integration of information for continuous improvement.
    5. Atmos commented that there is the potential for the risk model
process to handle unknown data in a more useful manner. Atmos suggested
that a higher risk score with ``known'' data attributes should be
considered more relevant for decisions on preventive and mitigative
measures than a similar score derived from ``unknown'' data attributes.
    6. Kern River suggested that industry-wide research into failure
probabilities and effectiveness of preventive and mitigative measures
would facilitate more rigorous quantitative models. Kern River noted
that vendors are continuously improving risk models.
    7. MidAmerican suggested that risk models could be improved with
better tracking, recording, and retrieval of assessment results. With
feedback and information sharing, refining coefficients within the
model will produce more accurate risk results.
    8. Northern Natural Gas reported that its risk assessment process
is improved every year and that its risk model vendor is heavily
involved with the company in understanding how the risk results are
used.
    9. Paiute and Southwest Gas suggested that risk models will be
improved as additional information is gained through an assessment
cycle and that this continuous improvement process will then repeat
through subsequent assessment cycles.
    10. Texas Pipeline Association and Texas Oil & Gas Association
observed that there is no `one size fits all' solution to this issue.
Response to Question E.5 Comments
    PHMSA appreciates the information provided by the commenters. The
comments speak in general terms about incremental improvement of
existing index-type or qualitative relative risk models. PHMSA believes
that such models, while appropriate and useful for limited purposes
such as ranking segments to prioritize baseline assessments, fall far
short of the type of model needed to fully execute a mature integrity
management program. PHMSA proposes to clearly articulate the
requirements for validation of the risk assessment and proposes to
clarify that an operator must ensure validity of the methods used to
conduct the risk assessment in light of incident, leak, and failure
history and other historical information. Additionally, the proposed
rule would require that validation must: (1) Ensure the risk assessment
methods produce a risk characterization that is consistent with the
operator's and industry experience, including evaluations of the cause
of past incidents as determined by root cause analysis or other means;
and (2) include analysis of the factors used to characterize both the
probability of loss of pipeline integrity and consequences of the
postulated loss of pipeline integrity.
    E.6. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
     The potential costs of modifying the existing regulatory
requirements pursuant to the commenter's suggestions.
     The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the
existing regulatory requirements.
     The potential environmental impacts of modifying the
existing regulatory requirements.

    No comments were received in response to this question.

F. Strengthening Requirements for Applying Knowledge Gained Through the
IM Program

    The ANPRM requested comments regarding strengthening requirements
related to operators' use of insights gained from implementation of an
IM program. IM assessments provide information about the condition of
the pipeline. Identified anomalies that exceed criteria in Sec.
192.933 must be remediated immediately (Sec.  192.933(d)(1)) or within
one year (Sec.  192.933(d)(2)) or must be monitored on future
assessments (Sec.  192.933(d)(3)). Operators are also expected to apply
knowledge gained through these assessments to assure the integrity of
their entire pipeline as part of its threat identification and risk
analysis process in accordance with Sec.  192.917.
    Section 192.917(e)(5) explicitly requires that operators must
evaluate other portions of their pipeline if an assessment identifies
corrosion requiring repair under the criteria of Sec.  192.933. The
operator must ``evaluate and remediate, as necessary, all pipeline
segments (both covered and non-covered) with similar material coating
and environmental characteristics.''
    Section 192.917 also requires that operators conduct risk
assessments that follow American Society of Mechanical Engineers/
American National Standards Institute (ASME/ANSI) B31.8S, Section

5, and use these analyses to prioritize segments for assessment, and to
determine what preventive and mitigative measures are needed for
segments in HCAs. Section 5.4 of ASME/ANSI B31.8S states that ``risk
assessment methods should be used in conjunction with knowledgeable,
experienced personnel . . . that regularly review the data input,
assumptions, and results of the risk assessments.'' That section
further states, ``an integral part of the risk assessment process is
the incorporation of additional data elements or changes to facility
data,'' and requires that operators ``incorporate the risk assessment
process into existing field reporting, engineering, and facility
mapping processes'' to facilitate such updates. Neither part 192 nor
ASME/ANSI B31.8S specifies a frequency at which pipeline risk analyses
must be reviewed and updated; instead, this is considered to be a
continuous, ongoing process. The following are general comments
received related to the topic as well as comments related to the
specific questions:
General Comment for Topic F
    1. MidAmerican suggested that application of knowledge gained
through integrity management should not be treated any differently than
any other information gained from work on or surveillance of the
pipeline. MidAmerican considers this to be adequately addressed by
Sec.  192.613.
Response
    PHMSA continues to believe that there are many important integrity
management requirements related to insights gained from implementation
of the IM program beyond those covered by the continuing surveillance
requirements of Sec.  192.613. Integrity management assessments provide
information about the condition of the pipeline and operators are
expected to apply the knowledge gained through these assessments to
assure the integrity of their entire pipeline. PHMSA believes that the
knowledge gained through IM assessments should be integrated into the
risk assessment process, which is not required by Sec.  192.613.
Comments Submitted for Questions in Topic F
    F.1. What practices do operators use to comply with Sec.
192.917(e)(5)?
    1. INGAA and a number of pipeline operators noted that operators
use available information and field knowledge to comply with this
requirement.
    2. AGA, supported by a number of its member companies, reported
that operator practices are too distinct and varied to list. AGA stated
that Sec.  192.917(e)(5) is prescriptive enough and no new requirements
are needed.
    3. GPTC and Nicor cited NACE SP0169 and NACE RP0177 as examples of
standards that can be used to guide compliance with Sec.
192.917(e)(5).
    4. Texas Pipeline Association and Texas Oil & Gas Association
commented that operators use cathodic protection surveys and/or spot
checks to determine whether failure is likely.
    5. Northern Natural Gas reported that it takes the actions
specified in Sec.  192.917(e)(5) and includes consideration of
incidents and safety related conditions.
    6. Kern River, Paiute, and Southwest Gas stated that they use root
cause evaluations of incidents to comply with Sec.  192.917(e)(5).
Response to Question F.1 Comments
    PHMSA appreciates the information provided by the commenters. The
comments provide little information related to specific operator
practices for compliance with Sec.  192.917(e)(5). PHMSA is not
proposing to amend Sec.  192.917(e)(5) at this time; however, PHMSA
proposes to clarify requirements in Sec.  192.917(b) to ensure that the
data gathering and integration process includes an analysis of both the
HCA segments and similar non-HCA segments and integrates information
about pipeline attributes and other relevant information, including
data gathered through integrity assessments.
    F.2. How many times has a review of other portions of a pipeline in
accordance with Sec.  192.917(e)(5) resulted in investigation and/or
repair of pipeline segments other than the location on which corrosion
requiring repair was initially identified?
    1. Based on a limited response by their members to a survey, Texas
Pipeline Association and Texas Oil & Gas Association reported that
repair of corrosion beyond the initially-identified anomaly is rare.
    2. Ameren Illinois reported that it has experienced two instances
in which it repaired other segments after identifying corrosion on a
covered pipeline segment.
    3. MidAmerican reported that it has experienced a few instances of
corrosion where coating was damaged during installation of a vent, and
some at air-to-soil interfaces.
    4. Northern Natural Gas has experienced no instances in which other
pipeline segments required repair. Northern added that corrosion wall
loss requiring repair is, itself, rare.
    5. Paiute and Southwest Gas reported that they had not identified
any immediate repair corrosion conditions.

Response to Question F.2 Comments

    PHMSA appreciates the information provided by the commenters. See
the response to question F.1.
    F.3. Do pipeline operators assure that their risk assessments are
updated as additional knowledge is gained, including results of IM
assessments? If so, how? How is data integration used and how often is
it updated? Is data integration used on alignment maps and layered in
such a way that technical reviews can identify integrity-related
problems and threat interactions? How often should aerial photography
and patrol information be updated for IM assessments? If the commenter
proposes a time period for updating, what is the basis for this
recommendation?
    1. INGAA and several pipeline operators reported that operators
update risk analyses whenever new information is obtained and
particularly after unexpected events.
    2. AGA, GPTC, Nicor, Kern River, and TransCanada commented that
risk analyses are updated at least annually.
    3. Northern Natural Gas reported that its procedures provide for
updating to include assessment results and changes in environmental
factors.
    4. Paiute and Southwest Gas reported that risk model updating is a
continuous process. Rankings are updated at 18- to 24-month intervals.
Ameren Illinois and Atmos similarly reported that updating is an
ongoing activity.
    5. Texas Pipeline Association and Texas Oil & Gas Association
commented that most operators have dedicated teams to perform risk
model updates.
    6. Alaska Department of Natural Resources commented that risk
models should be reviewed whenever significant operational or
environmental changes occur. AKDNR contended that risk models are not
valid if there are significant changes in these areas.
    7. NAPSR reported its conclusion that risk models should be updated
after every O&M activity or any finding that a required activity was
not performed.
    8. INGAA and a number of pipeline operators reported that data is
updated using a common spatial reference system, e.g., maps or tables,
and the frequency of data integration varies by operator.
    9. AGA, supported by a number of its member companies, reported
that data integration does not always involve use of geospatial tools.

    10. Atmos reported that it uses internal teams of subject matter
experts for data integration and that its maps are not layered for
technical data use.
    11. Northern Natural Gas, Paiute, and Southwest Gas stated that
they perform integration on alignment sheets based on integrity
management summaries and subject matter expert reviews.
    12. Texas Pipeline Association and Texas Oil & Gas Association
reported that many pipeline operators are migrating to GIS systems.
    13. INGAA and many pipeline operators commented that information
from aerial photography should be updated annually. They noted that
this would be consistent with the frequency of reviewing HCA
designations and operator budgeting and contended that more frequent
updates would not increase risk model accuracy. INGAA suggested that
other information, including information related to external events,
should be updated based on the nature and severity of experienced
events.
    14. AGA, Paiute, and Southwest Gas noted that not all operators use
aerial photography and expressed their belief that such use should not
be required. AGA noted that there are many tools, including routine
patrols, to gather data about the pipeline environment. A number of
member pipeline operators supported AGA's comments.
    15. Northern Natural Gas reported that it updates information
periodically, but with no set frequency. Northern noted that some areas
are stable while change can occur rapidly in others.
    16. Texas Pipeline Association and Texas Oil & Gas Association
recommended annual updates as a minimum. The associations noted that
this recognizes the time required to produce/acquire assessment data.
Response to Question F.3 Comments
    PHMSA appreciates the information provided by the commenters. After
review of the comments, PHMSA agrees that annual updates are desirable
and many operators perform full updates, or partial data updates (such
as updating aerial photos), annually. Some pipeline segments may be in
rapidly changing, dynamic environments, while others may remain static
for years. PHMSA also agrees that prescriptive requirements to perform
a full risk assessment annually are not necessary and potentially
burdensome, especially for very small operators, whose systems and
conditions do not change often. PHMSA is satisfied that the current
requirement, which contains a performance based requirement to update
risk assessments as frequently as needed to assure the integrity of
each HCA segment is adequate, if properly implemented, and is not
proposing a prescribed frequency at this time. However, PHMSA proposes
to clarify requirements in Sec. Sec.  192.917 and 192.937(b) to ensure
the continual process of evaluation and assessment is based on an
updated and effective data integration and risk assessment process as
specified in Sec.  192.917.
    F.4. Should the regulations specify a maximum period in which
pipeline risk assessments must be reviewed and validated as current and
accurate? If so, why?
    1. INGAA and numerous pipeline operators recommended that reviews
be annual, as suggested in PHMSA's Gas Integrity Management Program
Frequently Asked Question FAQ-234, arguing that this is practical and
sufficient (FAQs can be viewed at http://primis.phmsa.dot.gov/gasimp/faqs.htm).
    2. AGA, GPTC, and a number of other pipeline operators commented
that no maximum period should be specified for review of risk
assessments. These commenters argued that no one-size-fits-all interval
would be appropriate and expressed their conclusion that the current
requirements in Sec.  192.937 are adequate.
    3. California Public Utilities Commission recommended that reviews
be required annually, at intervals not to exceed 15 months, consistent
with other requirements within part 192.
    4. An anonymous commenter suggested that a specified review period
would be counterproductive, arguing that most operators would simply
default to the required interval, even if more frequent reviews were
appropriate.
Response to Question F.4 Comments
    PHMSA appreciates the information provided by the commenters. See
PHMSA response to comments related to Question F.3.
    F.5. Are there any additional requirements PHMSA should consider to
assure that knowledge gained through IM programs is appropriately
applied to improve safety of pipeline systems?
    1. INGAA and many pipeline operators opined that no new
requirements are needed in this area. They noted that prescriptive
requirements often become out of date as technology improves.
    2. AGA and numerous pipeline operators agreed that no new
requirements are needed, noting that existing regulations and sharing
of information through industry groups is sufficient.
    3. Texas Pipeline Association and Texas Oil & Gas Association
opined that existing requirements are adequate.
    4. Accufacts suggested that requirements should be more
prescriptive concerning threat evaluation and interactive threats, as
this is the heart of integrity management.
    5. An anonymous commenter suggested that new requirements be
established governing assessments conducted by pressure testing. The
commenter opined that the requirements in subpart J are inadequate and
represent an ``easy out'' for some operators.
Response to Question F.5 Comments
    PHMSA appreciates the information provided by the commenters. While
PHMSA believes that explicit requirements should be included to address
interactive threats, PHMSA also believes that prescriptive rules for
how an operator must evaluate interactive threats are not practical.
Therefore, PHMSA proposes to clarify performance-based requirements to
include an evaluation of the effects of interacting threats and for the
continual process of evaluation and assessment to include interacting
threats in identification of threats specific to each HCA segment.
Comments on integrity assessment methods are addressed in Topic G.
    F.6. What do operators require for data integration to improve the
safety of pipeline systems in HCAs? What is needed for data integration
into pipeline knowledge databases? Do operators include a robust
database that includes: Pipe diameter, wall thickness, grade, and seam
type; pipe coating; girth weld coating; maximum operating pressure
(MOP); HCAs; hydrostatic test pressure including any known test
failures; casings; any in-service ruptures or leaks; ILI surveys
including high resolution--magnetic flux leakage (HR-MFL), HR geometry/
caliper tools; close interval surveys; depth of cover surveys;
rectifier readings; test point survey readings; alternating current/
direct current (AC/DC) interference surveys; pipe coating surveys; pipe
coating and anomaly evaluations from pipe excavations; SCC excavations
and findings; and pipe exposures from encroachments?
    1. INGAA, supported by a number of pipeline operators, commented
that experience and information gained from a variety of sources,
including GIS data, corrosion data, ILI data/results, work management
activities, SCADA, encroachments, leaks etc., is utilized in data
integration. INGAA reported that operators have made major investments

in database applications to meet changing organizational and regulatory
requirements and to manage increasing volumes of data effectively.
Tools generally are available for integrating data into pipeline
knowledge databases. For integration purposes, the database must
contain adequate metadata elements such that dates, if important, and
location and length attributes are maintained. Currently-available
systems support these needs. INGAA expressed concern over use of the
term ``robust database,'' since this could be construed to mean that
all applicable data must be maintained in a common database or other
venue which does not meet the particular needs of the operator. INGAA
reported that it has an active Integrity Management--Continuous
Improvement (IMCI) team addressing improvement in these processes and
management systems.
    2. AGA, GPTC, and a number of pipeline operators commented that a
prescriptive requirement would be inappropriate because there is too
much variability among operators and their risk assessment methods. AGA
expressed its conclusion that there is no single methodology that
incorporates the wide variety of pipeline information used by
operators.
    3. MidAmerican suggested that an operator needs a robust computer
model to integrate diverse data dynamically into one table with one set
stationing.
    4. Kern River reported that it uses extensive GIS and cathodic
protection databases for these purposes.
    5. An anonymous commenter recommended that PHMSA require knowledge
of cathodic protection current level, amount, and direction of current
flow. The commenter opined that this information is not now generally
collected, and that it would allow for early detection of coating
failures and CP interferences.
Response to Question F.6 Comments
    PHMSA appreciates the information provided by the commenters. An
integral part of applying information from the IM Program to the risk
assessment and other analyses is the collection, validation, and
integration of pipeline data. PHMSA proposes to clarify the data
integration language in the requirements by repealing the reference to
ASME/ANSI B31.8S and including requirements associated with data
integration directly in the rule text: (1) Establishing a number of
pipeline attributes that must be included in these analyses, (2)
clarifying that operators must integrate analyzed information, and (3)
ensuring that data are verified and validated.
    F.7. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
     The potential costs of modifying the existing regulatory
requirements pursuant to the commenter's suggestions.
     The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the
existing regulatory requirements.
     The potential environmental impacts of modifying the
existing regulatory requirements.
    No comments were received in response to this question.

G. Strengthening Requirements on the Selection and Use of Assessment
Methods

    The existing IM regulations require that baseline and periodic
assessments of pipeline segments in an HCA be performed using one of
four methods:
    (1) In-line inspection;
    (2) Pressure test in accordance with subpart J;
    (3) Direct assessment to address the threats of external and
internal corrosion and SCC; or
    (4) Other technology that an operator demonstrates can provide an
equivalent understanding of the condition of line pipe.
    Operators must notify PHMSA in advance if they plan to use ``other
technology.'' Operators must apply one or more methods, depending on
the threats to which the HCA segment is susceptible. The ANPRM
requested comments related to the applicability, selection, and use of
each assessment method, existing consensus standards and requirements,
and the potential need to strengthen the requirements. The ANPRM then
listed questions for consideration and comment. The following are
general comments received related to the topic as well as comments
related to the specific questions:
General Comments for Topic G
    1. INGAA, supported by a number of its pipeline operator members,
noted that they are committed to work with technology providers and
researchers to improve the integrity management assessment capabilities
of its members. Further, INGAA members are sharing their experiences
with applying these new and improved assessment methods to specific
threats. INGAA opined that a great advantage of the integrity
management structure, as opposed to a prescriptive regulatory regime,
is the creation of an environment conducive to technological
development, innovation and improved knowledge.
    2. Accufacts suggested that a more prescriptive regulation is
needed clarifying the applicability and limitations of direct
assessment. Accufacts is concerned that operators are selecting direct
assessment due to a cost bias while ignoring that it cannot be used for
all threats and should not be used on some pipeline segments.
    3. Chevron commented that PHMSA should continue to allow operators
to select and use the most effective method to assess each pipeline
segment.
    4. NAPSR recommended that PHMSA implement a regulatory change that
requires both ILI and pressure testing for all transmission pipelines
and requires a reduction in MAOP until either the ILI or the pressure
tests are performed.
    5. MidAmerican, a gas distribution company, noted that many of its
transmission pipelines are short, small diameter lines that cannot be
pigged.
    6. Dominion East Ohio suggested that PHMSA should be funding more
research leading to the development of assessment tools, particularly
smart tools, to increase the number of assessment options available
rather than limiting the tools that can be used.
    7. A public citizen commented that pipe with unknown or uncertain
specifications should be subject to the most stringent testing
requirements.
    8. Two public citizens addressed required assessment intervals. One
suggested that all pipe that puts the public at significant risk should
be tested, by hydro testing or some other means, at approximately ten-
year intervals. Another commenter recommended that assessments be
required more frequently in densely populated areas.
    9. PST opined that the need to ask the questions in this section
makes clear that PHMSA's current level of oversight and review of IM
planning and implementation is inadequate, and calls into question the
value of many IM programs, particularly those relying to any extent on
direct assessment methods. PST recommended that the regulations be
significantly strengthened to require PHMSA's review and administration
approval of any IM program.
Response
    PHMSA appreciates the information provided by the commenters. PHMSA
agrees that pipeline operators should be able to select the best
assessment

method applicable for its pipelines and circumstances. PHMSA also
agrees with NAPSR and other commenters that additional requirements are
needed for assessing more miles of pipeline that pose a risk to the
public. PHMSA has also identified the need to address specific issues
related to the selection of integrity assessment methods that have been
identified following the San Bruno incident, especially related to the
use of direct assessment. Therefore, PHMSA proposes to add more
specific requirements related to (1) performance of integrity
assessments for pipe not covered by subpart O (i.e., pipeline not
located in a high consequence area) that represents risk to the public,
and (2) selection of assessment methods. Specifically, PHMSA proposes
to revise the requirements in Sec. Sec.  192.921 and 192.937 as
follows: (1) Allow direct assessment only if a line is not capable of
inspection by internal inspection tools; (2) add a newly defined
assessment method: ``spike'' hydrostatic test; (3) add excavation and
in situ direct examination as an allowed assessment method; and (4) add
guided wave ultrasonic testing (GWUT) as an allowed assessment method.
In addition, PHMSA proposes to add a new Sec.  192.710 to require that
a significant portion of pipelines not covered by subpart O be
periodically assessed using integrity assessment techniques similar to
those proposed for HCA segments. Specifically, PHMSA proposes to
require that all pipeline segments in class 3 and class 4 locations and
moderate consequence area as defined in Sec.  192.3 if the pipe segment
can accommodate inspection by means of instrumented inline inspection
tools (i.e., ``smart pigs''), be periodically assessed. Although PHMSA
proposes to provide selected, more prescriptive requirements for the
selection of assessment methods, the pipeline safety regulations would
continue to allow the use of other technology that an operator
demonstrates can provide an equivalent understanding of the condition
of the line pipe (comparable to a specified integrity assessment such
as pressure testing or inline inspection), in order to continue to
encourage research and development of more effective assessment
technologies similar to the successful development of GWUT. For non-HCA
segments, operator notification to PHMSA of the selection of other
technologies would not be required.
    PHMSA understands the Pipeline Safety Trust's recommendation that
the regulations require PHMSA's review and approval of any IM program.
PHMSA believes its current approach to inspection of operator IM
programs is both flexible and appropriate.
Comments Submitted for Questions in Topic G
    G.1. Have any anomalies been identified that require repair through
various assessment methods (e.g., number of immediate and total repairs
per mile resulting from ILI assessments, pressure tests, or direct
assessments)?
    1. INGAA reported that operators have used in-line inspection,
pressure testing, and direct assessment, with in-line inspection being
most prevalent. INGAA commented that all three methods have been
successful at identifying anomalies requiring repair. A number of
pipeline operators supported INGAA's comments.
    2. AGA and Ameren Illinois stated that all assessment methods used
by pipeline operators have been used to identify, or have identified,
anomalies requiring repair. A number of pipeline operators supported
AGA's comments.
    3. Accufacts recommended that PHMSA publically report the number of
anomalies discovered and repaired by anomaly type, time to repair,
state, and assessment method for both HCAs and non-HCAs.
    4. Texas Pipeline Association, Texas Oil & Gas Association, Atmos,
Paiute, and Southwest Gas noted that the transmission pipeline annual
report includes the number of immediate and scheduled anomalies
identified by each assessment method.
    5. ITT Exelis Geospatial Systems reported that aerial leak surveys
using laser technology, which is not one of the assessment methods
specified in the regulations, have been successful in identifying
pipeline leaks.
    6. Kern River reported that it did not identify any immediate or
scheduled repairs from January 1, 2004, through December 31, 2010.
    7. MidAmerican noted that it has used all three allowed assessment
methods. Approximately 42 percent of the company's pipeline has been
assessed using direct assessment. All anomalies requiring repair have
been identified using in-line inspection.
    8. Northern Natural Gas reported that it identified seven immediate
repair anomalies in the period from January 1, 2004, through December
31, 2010. The total number of repairs made during this same period
averaged 0.1 per mile.
    9. An anonymous commenter noted that few leaks are detected using
subpart J pressure testing.
    10. GPTC reported that it has no data with which to respond to this
question.
Response to Question G.1 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA
agrees that all three methods have been successful at identifying
anomalies requiring repair. However, by its nature, direct assessment
is a sampling-type assessment method. Hydrostatic pressure testing and
in-line inspection both assess the entire segment. PHMSA, therefore,
believes that these methods provide a higher level of assurance (though
still not 100%) that no injurious pipeline defects remain in the pipe
after the assessment is completed and anomalies repaired. Based on this
inherent difference, PHMSA proposes to revise the requirements to: (1)
Allow direct assessment only if a line is not capable of inspection by
internal inspection tools; (2) add a newly defined assessment method:
``spike'' hydrostatic test; (3) add excavation and in situ direct
examination as an allowed assessment method; and (4) add guided wave
ultrasonic testing (GWUT) as an allowed assessment method.
    G.2. Should the regulations require assessment using ILI whenever
possible, since that method appears to provide the most information
about pipeline conditions? Should restrictions on the use of assessment
technologies other than ILI be strengthened? If so, in what respect?
Should PHMSA prescribe or develop voluntary ILI tool types for
conducting integrity assessments for specific threats such as corrosion
metal loss, dents and other mechanical damage, longitudinal seam
quality, SCC, or other attributes?
    1. INGAA, supported by a number of its pipeline operator members,
noted that ILI is effective, but has its own limitations; pressure
testing and direct assessment can provide information that ILI cannot.
INGAA commented that operators must be allowed to use all assessment
techniques without encumbrances or conditions because all techniques
are effective.
    2. AGA and a number of its members commented that ILI is one option
of a variety of methods available to operators and suggested that
applying additional ILI assessment requirements would hinder operators'
ability to select the tool with the appropriate capabilities to address
pipeline threats. AGA commented that this would be inappropriate and
operators must be allowed to use any of the three assessment methods,
without conditions, based on the circumstances and threats applicable
to their pipelines.
    3. Air Products and Chemicals, Inc. opposed a requirement to use
ILI whenever possible. The company noted

that one of the benefits of the current IM framework is the flexibility
it provides to operators in how to achieve regulatory goals. Air
Products noted that use of alternative methods is already constrained
by regulation and contended that the existing limitations are adequate
and it would be inappropriate for PHMSA to specify particular tool
types for individual threats. Atmos agreed, noting that ILI is not the
only assessment method applicable to many threats. Atmos noted that ILI
technology is developing at a rapid pace, and suggested that
prescribing certain tool types could limit future advancements or cause
the rate of development to be slowed.
    4. TransCanada opposed requiring use of ILI. The company noted that
ILI has its advantages, but it also has limitations, and commented that
operators must be able to select the methods best suited to evaluate
identified threats, given the wide range of circumstances and threats
that may be applicable to particular pipeline segments.
    5. NACE International noted that assessments using only ILI do not
necessarily provide the most information about pipeline conditions;
other assessment methods may be more appropriate for some threats. NACE
also noted that not all pipelines are piggable. NACE believes that each
assessment method has strengths and weaknesses, each should be used
where appropriate, and overly prescriptive rules can supplant sound
engineering judgment, stifle innovation, and prevent the development of
new technologies.
    6. Accufacts commented that all new pipelines should be configured
to permit ILI and a timetable should be established to convert older
pipelines for ILI. At the same time, Accufacts cautioned that one
particular approach to ILI should not be oversold, and suggested that
limitations on use of certain assessment methods should be strongly
clarified in regulations. Accufacts suggested that PHMSA needs to
clarify the major strengths and weaknesses of the various assessment
methods identified and to improve subpart J, including requiring the
reporting of hydro testing pressure ranges, both minimum and maximum
pressures, as a percentage of SMYS when appropriate.
    7. MidAmerican suggested that operators be allowed to address
threats by category using the guidance in ASME/ANSI B31.8S. MidAmerican
noted that it cannot use ILI on all of its transmission pipelines, 42
percent of which have been assessed using direct assessment.
MidAmerican suggested that operators continue to use their threat
assessments to determine which pipelines should be retrofitted to
accommodate ILI.
    8. Northern Natural Gas reported that it uses ILI whenever possible
but it cannot be used on all of its lines due to their small diameter.
Northern noted that pressure testing and direct assessment may be more
appropriate for some threats and that the operator is responsible for
selecting the best assessment method. Northern opined that the guidance
on tool selection in ASME/ANSI B31.8S is sufficient.
    9. Texas Pipeline Association and Texas Oil & Gas Association
recommended that ILI not be the required assessment method of choice
and that operators continue to have the flexibility to select the
appropriate assessment method, noting that other methods may be better
for a particular threat. The associations noted that ILI technology is
improving rapidly and expressed concern that rulemaking cannot keep
pace with technological advancement and that prescribing tools could
result in assessments being conducted with inferior technology.
    10. Thomas M. Lael, an industry consultant, noted that no
assessment method, including ILI, is perfect. Lael suggested that use
of alternating methods be required to realize the strengths of all
methods.
    11. A citizen commenter suggested that use of direct assessment be
limited, since it does not provide sufficient information about the
pipeline.
    12. An anonymous commenter noted that requiring ILI would not be
cost beneficial, because corrosion metal loss is a relatively slow
process.
    13. GPTC noted that ILI cannot be used on all pipelines and
recommended that operators have the latitude to select the assessment
method most appropriate for their pipelines. Oleksa and Associates
similarly noted that ILI cannot be used on some pipelines.
    14. Paiute and Southwest Gas opposed a requirement to use ILI
whenever possible. The companies noted that ILI provides current pipe
conditions but no information on environmental conditions surrounding
the pipe. They commented that operators should not be discouraged from
using any appropriate assessment method.
    15. Ameren Illinois opposed requiring the use of ILI, noting that
it is neither practical nor feasible to require ILI assessments on all
pipelines.
    16. California Public Utilities Commission recommended that
pressure testing and ILI be the only methods allowed for IM
assessments. CPUC suggested that the use of direct assessment be
limited to confirmatory direct assessments and lines that have been
pressure tested to subpart J requirements. CPUC further recommended
that the regulations prescribe acceptable ILI tool types to address
specific threats.
    17. A private citizen suggested that pressure testing should not be
allowed as an assessment method because it provides no information
about anomalies not resulting in leaks or failures. The commenter
suggested that use of pressure testing should be limited to verifying
the integrity of new or repaired pipelines.
Response to Question G.2 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA
agrees that operators should be able to select the methods best suited
to evaluate identified threats. However, PHMSA believes rulemaking for
strengthening requirements for the selection and use of assessment
methods is needed to address specific issues identified from the San
Bruno incident. PHMSA proposes more prescriptive guidance for the
selection of assessment methods, especially related to the use of
direct assessment and to assess for cracks and crack-like defects, as
indicated in the response to general comments, above. For HCA segments,
PHMSA proposes that the use of direct assessment as the assessment
method would be allowed only if the pipeline is not capable of being
inspected by internal, in-line inspection tools. For non-HCA segments,
assessments would have to be done within 15 years and every 20 years
thereafter. To facilitate the identification of non-HCA areas that
require integrity assessment, PHMSA proposes to define a ``Moderate
Consequence Area'' or MCA. PHMSA also proposes additional requirements
for selection and use of internal inspection tools, including a
requirement to explicitly consider uncertainties such as tool tolerance
in reported results in identifying anomalies.
    PHMSA disagrees with the suggestion that pressure testing should
not be allowed as an assessment method. In many circumstances, pressure
testing is a good indicator of a pipeline's integrity. Although it does
not assess subcritical defects, it provides assurance of adequate
design safety margin and can be useful in particular for lines that are
not piggable.
    G.3. Direct assessment is not a valid method to use where there are
pipe properties or other essential data gaps. How do operators decide
whether their

knowledge of pipeline characteristics and their confidence in that
knowledge is adequate to allow the use of direct assessment?
    1. Industry commenters, including AGA, INGAA, Texas Pipeline
Association, Texas Oil and Gas Association, and numerous pipeline
operators noted that the requirements applicable to direct assessment,
specified in NACE Standard SP0502-2008 and incorporated into subpart O
by reference, require a feasibility study to determine if use of direct
assessment is appropriate. If it cannot be determined during the pre-
assessment phase that adequate data is available, another assessment
method must be selected. Industry commenters noted that it is the
operator's responsibility to select an appropriate assessment method.
    2. Paiute and Southwest Gas disagreed with the statement that
``direct assessment is not a valid method to use where there are pipe
properties or other essential data gaps.'' The companies noted that the
data gathered and evaluated conforms to Section 4 of ASME/ANSI B31.8S
(incorporated by reference) which allows use of conservative proxy
values when data gaps exist.
    3. California Public Utilities Commission recommended that pressure
testing and ILI be the only methods allowed for IM assessments. CPUC
suggested that use of direct assessment be limited to confirmatory
direct assessments and lines that have been pressure tested to subpart
J requirements.
Response to Question G.3 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA
agrees that pressure testing and ILI are preferred integrity assessment
methods, over direct assessment. However, when properly implemented, DA
can be a valuable integrity assessment tool. PHMSA proposes to retain
direct assessment as an assessment method where warranted, but proposes
to revise the requirements in Sec. Sec.  192.921 and 192.937 to allow
use of direct assessment or other method only if a line is not capable
of inspection by internal inspection tools.
    G.4. How many miles of gas transmission pipeline have been modified
to accommodate ILI inspection tools? Should PHMSA consider additional
requirements to expand such modifications? If so, how should these
requirements be structured?
    1. A number of industry commenters submitted data concerning the
number of pipeline miles that have been modified to accommodate ILI:
     INGAA reported that more than 30,000 miles of pipeline
have been modified across the industry.
     Atmos reported that it has modified approximately 2,800
miles.
     Northern Natural Gas reported that it has modified
approximately 2,500 miles.
     MidAmerican reported that it has modified 38 miles.
     Paiute and Southwest Gas reported that they have made
modifications but have not tracked the total mileage on which they were
performed.
     Ameren Illinois and Kern River reported that they have
modified no pipelines. Kern River noted specifically that all of its
mainline is piggable.
    2. AGA reported that it has no data concerning the number of miles
modified, but noted that operators are required to assure that new and
replaced pipelines can accommodate ILI tools. AGA contended that
modifying pipelines to accommodate ILI tools is more onerous for
intrastate transmission pipeline operators than for interstate
operators. A number of operators supported AGA's comments.
    3. Texas Pipeline Association and GPTC reported that they have no
data with which to respond to this question.
    4. California Public Utilities Commission supported additional
requirements to expand modifications to accommodate ILI but reported
that it has no opinion on how these requirements should be structured.
    5. MidAmerican noted that one-third of its 770 miles of
transmission pipeline is of a diameter smaller than available ILI
tools.
    6. Northern Natural Gas commented that PHMSA should not consider
additional requirements to expand modifications of pipelines to
accommodate ILI tools, and that the inspection method and determination
to assess additional line segments outside of HCAs should be based on
specific risk factors and type and configuration of pipeline facility.
The company noted that some lines cannot be assessed using ILI.
    7. Paiute and Southwest Gas noted that Sec.  192.150 requires that
newly constructed or replacement pipelines be designed to accommodate
ILI tools. They contended that the decision to modify other pipelines
should be an operator decision based on the best assessment method.
    8. Texas Pipeline Association and Texas Oil & Gas Association
opined that PHMSA does not need to develop additional requirements for
the modification of transmission pipelines to accommodate ILI tools.
The associations noted that the regulations already cover this for new
and replacement pipelines and that there is a financial incentive for
operators to use ILI tools versus other assessment methods. Atmos
agreed, also noting that there are numerous advantages to ILI that
incentivize operators to use that method when they can.
    9. Accufacts commented that PHMSA should report publicly the number
of miles of transmission pipeline that can be inspected by ILI as well
as the number of miles inspected by other assessment methods both for
HCAs and non-HCAs.
Response to Question G.4 Comments
    PHMSA appreciates the information provided by the commenters. In
its report on the San Bruno incident, the NTSB recommended that all
natural gas transmission pipelines be configured so as to accommodate
in-line inspection tools, with priority given to older pipelines
(recommendation P-11-17). In its initial response to the NTSB
recommendation, PHMSA stated that implementing this recommendation will
involve significant technical and economic challenges and is likely to
require time to implement. Additional data is needed to evaluate this
issue. Therefore, further rulemaking will be considered separately in
order to complete this evaluation. PHMSA will review the comments
received on the ANPRM and will address this issue in the future.
    G.5. What standards are used to conduct ILI assessments? Should
these standards be incorporated by reference into the regulations?
Should they be voluntary?
    1. INGAA, supported by a number of its operator members, noted that
standards are continuously upgraded and improved and recommended that
PHMSA adopt performance-based language that will allow operators to
select appropriate standards.
    2. AGA, supported by a number of its members, noted that ILI
technology is advancing rapidly and it would be unwise to restrict
innovation by handcuffing it to a slow-developing rulemaking process.
AGA recommended that PHMSA not adopt ILI standards into the code.
Ameren Illinois agreed that standards should not be incorporated,
because to do so would limit operators' ability to use up-to-date
standards.
    3. GPTC argued that there is no justification to enact additional
prescriptive regulations for ILI assessments of pipelines. GPTC
contended that performance standards allow operators to select the best
approach.

    4. Atmos, MidAmerican, Northern Natural Gas, Paiute, and Southwest
Gas all cited one or more of API1163, ASNT ILI-PQ-2005 and RP0102-2002,
and ASME/ANSI B31.8S as standards used to conduct ILI assessments. All
agreed that use of industry standards should remain voluntary. Paiute
and Southwest Gas, in particular, commented that technology is
developing rapidly, and that incorporating current standards into the
regulations may hold operators accountable to a level of performance
that may be outdated.
    5. Texas Pipeline Association and Texas Oil & Gas Association also
opposed incorporating ILI standards into the regulations. TPA commented
that there are incentives for operators to take appropriate measures to
obtain accurate and reliable ILI results.
    6. An anonymous commenter suggested that incorporating standards
could be counterproductive, since operators would usually stop with the
required actions. The commenter suggested that a better approach would
be to require operators to have precise specifications, guidelines, and
a written process for ILI, none of which should be developed by the
operator's ILI vendor. The commenter also suggested that a similar
approach be adopted for stress corrosion cracking direct assessment
(SCCDA).
    7. California Public Utilities Commission and a private citizen
recommended that standards be incorporated for mandatory compliance,
arguing that this is necessary to assure quality and accuracy.
Response to Question G.5 Comments
    PHMSA appreciates the information provided by the commenters. The
current pipeline safety regulations in 49 CFR 192.921 and 192.937
require that operators assess the material condition of pipelines in
certain circumstances and allow use of in-line inspection tools for
these assessments. Operators are required to follow the requirements of
ASME/ANSI B31.8S in selecting the appropriate ILI tools. ASME B31.8S
provides limited guidance for conducting ILI assessments. At the time
these rules were promulgated, there was no consensus industry standard
that addressed ILI. Three related standards have been published: API
STD 1163-2005, NACE SP0102-2010, and ANSI/ASNT ILI-PQ-2010. These
standards address the qualification of inline inspection systems, the
procedure for performing ILI, and the qualification of personnel
conducting ILI, respectively. The incorporation of these standards into
pipeline safety regulations will promote a higher level of safety by
establishing consistent standards. Therefore, PHMSA is proposing to
incorporate these industry standards into the regulations to provide
better guidance for conducting integrity assessments with in-line
inspection. PHMSA also encourages and actively supports the development
of new and better technology for integrity assessments. Therefore, the
rule also allows the application and use of new technology, provided
that PHMSA is notified in advance. PHMSA will continue to evaluate the
need for additional guidance for conducting integrity assessments or
applying new technology.
    G.6. What standards are used to conduct internal corrosion direct
assessment (ICDA) and SCCDA assessments? Should these standards be
incorporated into the regulations? If the commenter believes they
should be incorporated into the regulations, why? What, if any,
remediation, hydrostatic test or replacement standards should be
incorporated into the regulations to address internal corrosion and
SCC?
    1. INGAA commented that standards exist for ICDA and SCCDA. AGA
agreed that NACE SP0206 addresses ICDA and SP0204 addresses SCCDA. AGA
opposed adopting these standards into the regulations, however,
commenting that a standard must be demonstrated to be effective before
it can be incorporated. AGA noted that there are long-standing issues
with the ICDA standard. Numerous pipeline operators provided comments
supporting the INGAA and AGA comments.
    2. GPTC, Atmos, Ameren Illinois, MidAmerican, Paiute, Southwest
Gas, Texas Gas Association and Texas Oil & Gas Association all
referenced one or more of: NACE SP0502, NACE SP0206, ASME/ANSI B31.8S,
and GRI02-0057. All agreed that the standards should not be
incorporated by reference, arguing that this would stifle innovation or
require operators to follow requirements that may become outdated, or
both. Paiute and Southwest Gas specifically recommended that PHMSA
collect additional information on industry best practices and compile/
review IM results related to internal corrosion and SCC before taking
any action towards incorporating the standards.
    3. NACE International reported its conclusion that the existing
standards for ICDA and SCCDA should be incorporated into regulations.
NACE also cautioned that overly-prescriptive regulations can prevent
innovation and development of new technologies.
    4. Northern Natural Gas reported that it used NACE SP0206 in
developing its ICDA procedures and there would be no impact on the
company if the standard were adopted into regulations. Northern further
reported it does not use SCCDA.
    5. Accufacts commented that few technical gains have been made in
the abilities of direct assessment methods to reliably identify or
assess at-risk anomalies, especially with regards to SCC.
    6. California Public Utilities Commission argued that pressure
testing and ILI should be the only assessment methods allowed. The
Commission contended that direct assessment should be limited to use
during confirmatory direct assessments and for lines that have been
pressure tested to subpart J requirements.
    7. An anonymous commenter noted that Kiefner, NACE, and ASTM all
provide useful references for SCCDA and ICDA.
    8. INGAA, supported by several of its operator members, noted that
ASME/ANSI B31.8S addresses remediation and pressure testing. INGAA
recommended that PHMSA adopt the 2010 version of this standard, arguing
that it is improved over the 2004 standard that is currently
incorporated by reference into Section 192.7 and that it addresses
near-neutral SCC. The 2010 edition also includes specific guidance for
SCC mitigation by means of hydrostatic pressure testing in the event
SCC is identified on a pipeline.
    9. MidAmerican reported that it uses ASME B31G to determine
remaining wall strength and that it remediates conditions in accordance
with Sec.  192.933(d) and ASME/ANSI B31.8S.
Response to Question G.6 comments
    PHMSA appreciates the information provided by the commenters.
Section 192.927 specifies requirements for gas transmission pipeline
operators who use ICDA for IM assessments. The requirements in Sec.
192.927 were promulgated before there were consensus standards
published that addressed ICDA. Section 192.927 requires that operators
follow ASME/ANSI B31.8S provisions related to ICDA. PHMSA has reviewed
NACE SP0206-2006 and finds that it is more comprehensive and rigorous
than either Sec.  192.927 or ASME B31.8S in many respects. In addition,
Section 192.929 specifies requirements for gas transmission pipeline
operators who use SCCDA for IM assessments. The requirements in Sec.
192.929 were promulgated before there were consensus industry standards
published that addressed SCCDA. Section 192.929 requires that operators
follow Appendix A3 of ASME/ANSI B31.8S. This appendix provides some
guidance for

conducting SCCDA, but is limited to SCC that occurs in high-pH
environments. Experience has shown that pipelines also can experience
SCC degradation in areas where the surrounding soil has a pH near