PHMSA acknowledges that estimates of hydrostatic test costs can
vary and that there is risk in using overstated estimates in the
analysis of benefits and costs since regulatory decisions regarding
public safety can be based on these results. For the Preliminary
Regulatory Impact Assessment (PRIA) for this proposed rule PHMSA used
vendor pricing data to develop unit costs for pressure testing. These
costs represent the contractor's costs to complete an eight hour
pressure test for

various segment diameters and lengths. PHMSA applied a multiplier to
account for other operator costs, such as manifold installation and
operational oversight, and also added estimated costs to provide
temporary gas supplies and the market value of lost gas. Based on these
data and assumptions, PHMSA estimated per mile pressure test costs
range from approximately $60,000 per mile (12'' diameter, 10 mile
segment) to 630,000 (36'' diameter, one mile segment). Detailed
explanations of these unit costs are available in the PRIA, provided in
the regulatory docket.
    8. AGA and several pipeline operators suggested PHMSA should
establish jointly with industry a committee to evaluate pipeline data
and to determine whether more data is needed. They commented industry
has repeatedly made this request and PHMSA has, to date, not responded.
They contended PHMSA's current analysis of pipeline safety performance
data is inadequate. Similarly, Panhandle Energy noted a number of the
questions in the ANPRM requested data on various subjects; Panhandle
expressed its belief that PHMSA collects and has access to at least
some of data requested, and this data, collected pursuant to regulatory
requirements, should be more complete, and consistently collected and
reported, than piecemeal collections of data in response to this ANPRM.
Expressing a somewhat contrary view, El Paso suggested more data should
be collected and analyzed before notices of proposed rulemakings are
prepared; PHMSA needs to collect and analyze data to determine the
proper path for future requirements, if any.
Response
    In response to NTSB recommendation P-11-19, PHMSA held a pipeline
safety data workshop in January 2013. The workshop: (1) Summarized the
data OPS collects, who it is collected from, and why it is collected;
(2) addressed how stakeholders, including OPS, industry, and the public
use the data; (3) addressed data quality improvement efforts and
performance measures; and (4) discussed the best method(s) for
collecting, analyzing, and ensuring transparency of additional data
needed to improve performance measures. PHMSA considered the results of
the workshop as well as the comments to the ANPRM related to pipeline
safety performance data.
    9. APGA suggested PHMSA revise the definitions of transmission and
distribution pipelines to be more risk-based. APGA contended that the
current definitions are not risk-based and lead to inappropriate
outcomes. In particular, classification of some pipelines as
``transmission'' based on functional aspects of the current definition
leads to inappropriate application of requirements. In a similar vein,
Oleksa and Associates suggested it may be time to reduce IM
requirements on low-stress transmission pipelines, which pose lower
risk than high-stress lines. Texas Pipeline Association and Texas Oil &
Gas Association commented PHMSA should not extrapolate experience with
interstate pipelines to intrastate lines, which differ in design and
operation.
Response
    The definition of transmission vs. distribution pipelines and the
applicability requirements for integrity management in High Consequence
Areas is not within the scope of this proposed rule. The general topic
of the scope and applicability of integrity management is addressed in
the class location report which available in the docket.
    10. Northern Natural Gas recommended all exemptions from one-call
requirements be eliminated. They noted excavation damage remains, by
far, the single greatest threat to pipeline safety and management of
excavation damage, through one-call programs, has been demonstrated to
be an effective means of countering that threat.
Response
    This comment is not within the scope of the ANPRM topics. However,
PHMSA has revised the pipeline safety regulations related to pipeline
damage prevention programs, which includes one-call programs, in an
final rule issued July 23, 2015 (80 FR 43836).
    11. The Gas Processors Association, Texas Pipeline Association, and
Texas Oil & Gas Association commented regarding current efforts to
clarify the applicability of part 192 requirements, particularly
requirements for distribution integrity management, to farm taps. They
suggested PHMSA is engaged in an expansion of requirements in this area
without notice or a demonstrated safety need. They suggested PHMSA
initiate a rulemaking specifically to clarify requirements applicable
to farm taps.
Response
    Treatment of farm taps is not within the scope of the ANPRM topics.
However, PHMSA has engaged in dialogue with industry on this topic and
will continue to consider options to address this issue in a separate
action.
    12. Northern Natural Gas suggested PHMSA reduce the time allowed
for conducting a baseline assessment in cases where a new HCA is found,
tailored to the circumstances of the particular segment. Northern
expressed its belief this would address threats to integrity in areas
affecting population more quickly than current requirements.
Response
    Currently, Sec.  192.905(c) requires that newly identified HCAs be
incorporated into the baseline assessment plan within one year. PHMSA
does not currently have plans to address this requirement. However,
periodically DOT or PHMSA seeks public input on retrospective review of
existing regulations under Executive Order 13563. PHMSA encourages the
commenter to raise this issue the next time DOT or PHMSA solicits
comments on retrospective review of existing regulations.
    13. Alliance Pipeline suggested many pipeline safety questions can
be answered by applying INGAA's five guiding principles of pipeline
safety. They noted INGAA has developed the Integrity Management-
Continuous Improvement (IMCI) Initiative to implement these principles
and suggested PHMSA actively engage with INGAA in developing workable
solutions to pipeline safety issues.
Response
    PHMSA appreciates the industry efforts to improve pipeline safety
and is committed to working with all stakeholders toward this end.
    14. Paiute Pipeline and Southwest Gas commented integrity
management requirements have not been in effect long enough to gauge
their effectiveness and decide whether additional changes are needed.
The companies noted the first, baseline assessments of pipeline
segments subject to those requirements are only now being completed.
AGA and other pipeline operators agreed, noting IM is still new,
operators are still refining their processes, and PHMSA should approach
change with caution.
Response
    While the first round of baseline assessments are only now being
completed, the gas IM rule has been in place approximately 10 years.
PHMSA expects that operator IM programs should have significantly
matured in this timeframe.
    15. Panhandle Energy suggested that PHMSA evaluate rule changes
that could have prevented incidents which occurred in recent years. Any
initiatives that would not have contributed to improved safety, they
suggest, should be postponed or treated as lower priority activities.
Panhandle suggested rulemaking without a sound basis is not

only ineffective but counterproductive in that it diverts resources
that could have been used to improve safety. Questar Gas similarly
commented PHMSA needs to minimize unnecessary activities that
inappropriately divert safety resources. Questar also recommended that
PHMSA explicitly consider the diversity within the regulated community.
Response
    One of the major motivations for PHMSA's issuance of the ANPRM was
to solicit information useful to ensuring that pipeline safety reforms
have a sound basis. PHMSA is also required by Executive Orders 12866
and 13563 to ensure that the benefits of its rules justify the costs,
to the extent permitted by law. PHMSA has prepared an initial
regulatory impact analysis for this proposed rule, which is available
in the docket for this rule. PHMSA encourages the commenter as well as
other members of the public to review the analysis and provide input
for improving the final rule.
    16. AGA and several pipeline operators commented that, while
enhancements can be made, IM requirements need not be subjected to
wholesale change. They cited GAO and NTSB reports on the efficacy of
transmission pipeline integrity management and the lack of pipeline
safety issues among the NTSB's ``Most Wanted'' issues.
Response
    While PHMSA believes that IM has led to improvements in managing
pipeline integrity, recent incidents and accidents demonstrate that
much work remains to improve pipeline safety.
    17. AGA and pipeline operators noted that transmission and
distribution integrity management are not distinct activities for most
intrastate pipeline operators. They contended that the ANPRM seemed to
be based on a presumption that operators manage their transmission and
distribution pipeline safety differently, and that this assumption is
without basis.
Response
    PHMSA has promulgated specific IM rules for both transmission and
distribution systems with a view toward allowing operators to customize
their performance based programs as appropriate to their specific
systems.
    18. AGA and several pipeline operators suggested that any changes
to public awareness requirements should be made at the state level.
They noted that federal requirements in this area are new and that
effectiveness reviews are still in progress.
Response
    This issue is not within the scope of the ANPRM. However, PHMSA has
revised the pipeline safety regulations related to pipeline damage
prevention programs in a final rule issued July 23, 2015 (80 FR 43836).
    19. NACE International suggested that adopting its standards for
corrosion control would be the best means to accomplish the goal of
maintaining pipelines safe and functional for long periods of time.
Response
    This NPRM proposes to incorporate industry consensus standards into
the regulations for assessing the physical condition of in-service
pipelines using in-line inspection, internal corrosion direct
assessment, and stress corrosion cracking direct assessment. In
addition, this NPRM proposes to enhance subpart I requirements for
corrosion control and to revise Appendix D to improve requirements for
cathodic protection.
    20. The NTSB commented that regulations for gas transmission
pipelines can and should be improved and expressed its support for the
overall intent of the ANPRM. The NTSB noted publication of the ANPRM
prior to its recommendations resulting from the San Bruno incident
investigation precluded any mention in the ANPRM of these NTSB safety
recommendations. The NTSB suggested PHMSA should seek comment on its
recommendations.
Response
    PHMSA has reviewed the NTSB recommendations that were issued on
September 26, 2011 and found that several recommendations related
directly to the topics addressed in the ANPRM and that may impact the
proposed approach to rulemaking. The topics impacted are discussed
above in the Background section above, in sections II.C and II.E, and
include NTSB Recommendations P-11-10, P-11-11, P-11-14, P-11-15, P-11-
17, and P-11-19. The NTSB's other recommendations will be addressed in
separate proceedings.
    21. El Paso suggested that the proper approach to attain the
highest pipeline safety levels is through a structured, deliberate
rulemaking that closely examines all issue aspects prior to making
informed decisions.
Response
    PHMSA agrees and is taking a careful, structured, and phased
approach to enhancing pipeline safety regulations and IM performance
standards.
    22. Thomas M. Lael, a pipeline industry consultant, suggested any
new regulations be concise and clear. He contended past lack of clarity
has created the need for many re-interpretations and enforcement
problems.
Response
    PHMSA concurs but also notes that performance-based regulations, by
their nature, are not as specific, nor as easily measurable, as
prescriptive regulations, but are more likely to improve safety and the
cost-effectiveness of regulations. PHMSA provides guidance to help
stakeholders understand the intent and scope of performance-based
regulations.
General Public Comments
    1. A member of the public stated that the ANPRM did not provide
specific options for consideration. As written, only those with direct
involvement in the industry could understand it well enough to comment.
Presenting the options more specifically would allow for better
informed public comment. The discussion should also include a regional
component, since issues affecting different states/regions are not the
same.
Response
    By its nature, the ANPRM did not propose specific alternatives or
rules, but solicited input to help inform future proposals. This NPRM
provides specific proposed rules for public comment.
    2. The Alaska Natural Gas Development Authority stated that the
regulations should require consideration of earthquakes, as recent
history shows they can be very important to safety of high-pressure gas
lines.
Response
    Section 29 of the Act states that in identifying and evaluating all
potential threats to each pipeline segment, an operator of a pipeline
facility shall consider the seismicity of the area. Rulemaking for this
issue is addressed in this NPRM and would add requirements to
explicitly reference seismicity for data gathering and integration,
threat identification and implementation of preventive and mitigative
measures.
    3. The Environmental Defense Fund pointed out that methane is a
very potent greenhouse gas. They commented that PHMSA should consider
and minimize the potential environmental effects of any future
rulemaking. They suggested EPA's Natural Gas Star program as a model.

Response
    The proposals in this rulemaking are designed to minimize the risk
of pipeline failures, which will result in environmental benefits. The
draft environmental assessment addresses the environmental effects of
this rulemaking.
    In addition, the RIA provides estimates of the environmental
benefits of this proposed rule. Natural gas transported in transmission
pipelines contains heat-trapping gases that contribute to global
climate change and its attendant societal costs. Of these gases, of
primary importance for evaluation are methane--by far, the largest
constituent of natural gas--and carbon dioxide. Other natural gas
components (ethane, propane, etc.) contribute as well, but they account
for a much smaller percentage of the natural gas mixture and, as a
result, are much less significant than methane in terms of their
environmental impact. The proposed rule is expected to prevent
incidents, leaks, and other types of failures that might occur, thereby
preventing future releases of greenhouse gases (GHG) to the atmosphere,
thus avoiding additional contributions to global climate change. PHMSA
estimated net GHG emissions abatement over 15 years of 69,000 to
122,000 metric tons of methane and 14,000 to 22,000 metric tons of
carbon dioxide, based on the estimated number of incidents averted and
emissions from pressure tests and ILI upgrades.
    4. A member of the public questioned the openness and clarity of
PHMSA's enforcement of pipeline safety regulations, and the use of
civil penalty revenues.
Response
    This comment is not within the scope of the ANPRM topics, however,
it should be noted that PHMSA embraces transparency in its regulatory
oversight program and has established a Pipeline Safety Stakeholder
Communications Web site, http://primis.phmsa.dot.gov/comm/, which
presents a variety of reports detailing enforcement activity. These
reports are offered on both nationwide and operator-specific bases.
    5. One member of the public suggested that DOT define ``safe
corridors'' for above-ground construction of pipelines. The commenter
suggested this would be similar, in principle, to the interstate
highway system. It would help to keep pipelines separated from
residences, avoid corrosive environments, and make pipelines available
for routine direct examination. At a minimum, this commenter suggested
the regulations should specify a minimum separation between new
pipelines and residences, as does the New Jersey state code, or
homebuyers be informed when a home is within the potential impact
radius of a gas transmission pipeline so they may make an informed
buying decision.
Response
    This comment addresses pipeline siting and routing, which is
outside the scope of PHMSA's statutory authority. As specified in 49
U.S.C. 60104, Requirements and Limitations of the Act, PHMSA is
prohibited from regulating activities associated with locating and
routing pipelines. Paragraph (e) of the statute states ``Location and
routing of facilities.--This chapter does not authorize the Secretary
of Transportation to prescribe the location or routing of a pipeline
facility.'' However, PHMSA is an active participant in the Pipeline and
Informed Planning Alliance (PIPA) and encourages all stakeholders to
learn about, and become involved with, PIPA. More information can be
obtained online at: http://primis.phmsa.dot.gov/comm/pipa/landuseplanning.htm.
    6. One member of the public noted there is an increasing trend in
significant incidents and suggested that this trend may be related to
undue influence of the pipeline industry on the regulations under which
it operates. The commenter recommended regulations should not be
weakened in favor of industry. The League of Women Voters of
Pennsylvania also recommended that regulatory agencies be insulated
from political and other influences of natural gas pipeline companies
to avoid the appearance of a conflict of interest.
Response
    PHMSA appreciates these comments. PHMSA is committed to improving
pipeline safety, and that is the goal of this endeavor. Significant
incidents on Gas Transmission (GT) pipelines have averaged between 70
and 80 incidents per year over the past 9 years. The existing integrity
management regulations in 49 CFR part 192, subpart O, addresses
pipeline integrity in HCAs, which is only about 7 percent of the GT
pipeline mileage. This proposed NPRM is focused on strengthening
requirements in HCAs and applying integrity management principles to
areas outside HCAs to better address safety issues. In addition, the
proposed rule seeks to address significant issues that caused or
contributed to the San Bruno accident, which include lack of pressure
test, inadequate records, poor materials, and inadequate integrity
assessment. The operator reports submitted to PHMSA as mandated by the
Act confirm that these issues are widespread for both HCA and non-HCA
pipe segments.
    7. The Harris County Fire Marshall's Office (HCFM) suggested
stiffer regulations are needed for gas transmission pipeline safety,
because of the large potential for negative impact and catastrophic
consequences. HCFM expressed concern about corrosion control and
current inspection practices for aging transmission infrastructure.
Response
    This NPRM proposes enhanced corrosion control requirements,
including periodic close interval surveys, post construction surveys
for coating damage, and interference current surveys. This NPRM also
proposes enhanced requirements for internal corrosion and external
corrosion management programs.
    8. The Pipeline Safety Trust (PST) commented that the ANPRM,
itself, may heighten and fuel existing public concerns about pipeline
safety. PST noted that many of the questions asked the industry to
provide information they believe the public would believe PHMSA should
already have. PST expressed its view that the number and types of
questions asked in the ANPRM reflect gaps in PHMSA's knowledge of gas
transmission pipeline systems and operator practices.
Response
    PHMSA appreciates these comments. PHMSA is committed to improving
pipeline safety and stakeholder input is valuable to the regulatory
process.
    9. Professional Engineers in California Government (PECG) commented
that private companies should not be solely responsible for the safety
of their pipelines. PECG contended that this approach has not worked.
PECG also suggested PHMSA examine options for increasing the number of
inspectors at state pipeline regulatory agencies and require public
inspectors be on site for pipeline construction and testing. They
contended such inspection is necessary to assure that older pipelines
are tested adequately and replaced when needed.
Response
    PHMSA appreciates these comments. PHMSA is committed to ensuring
that operators maintain and operate their pipelines safely. This
rulemaking contains a number of measures aimed at enhancing oversight.
    10. The City and County of San Francisco (CCSF) noted the scope of
potential rulemaking discussed in the

ANPRM did not include consideration of PHMSA's coordination with and
oversight of state certified agencies. In order to ensure the proper
oversight over natural gas transmission operators and the safe
operation of natural gas transmission lines, CCSF believes PHMSA must
address its state certification program and its oversight of state
enforcement of pipeline safety standards. CCSF recommended PHMSA
publish regulations for certification of state programs. They cited
NTSB recommendation P-11-20 and asserted PHMSA has not corrected
inadequate practices of the California Public Utilities Commission.
Response
    This comment is outside the scope of this rulemaking. PHMSA is
addressing NTSB recommendation P-11-20 separately.
    11. Two members of the public suggested the processes of the
Federal Energy Regulatory Commission (FERC) for siting pipelines should
be revised. One suggested a Commission on Public Accountability and
Safety Standards be established, consisting of a majority of local
public officials, first responder experts, and independent qualified
engineers, to make recommendations for FERC's pre-application process
and standards. The purpose would be to assure standards require public
accountability for review and vetting of pipeline safety issues with
local authorities when pipelines are proposed. The other commenter
suggested the relationship between FERC and DOT should be clarified,
that a company's enforcement history be taken into account in siting
decisions, and PHMSA be a full party to all FERC proceedings. The
commenter believes this is necessary because FERC does not have a
public safety mandate.
Response
    PHMSA is a separate agency from FERC and has no statutory authority
with respect to pipeline siting or approval. As specified in 49 U.S.C.
60104, Requirements and Limitations of the Act, PHMSA is prohibited
from regulating activities associated with locating and routing
pipelines. Paragraph (e) of the statute states ``Location and routing
of facilities.--This chapter does not authorize the Secretary of
Transportation to prescribe the location or routing of a pipeline
facility.'' However, PHMSA is an active participant in the Pipeline and
Informed Planning Alliance (PIPA) and encourages all stakeholders to
learn about, and become involved with, PIPA. More information can be
obtained online at: http://primis.phmsa.dot.gov/comm/pipa/landuseplanning.htm.
    12. Two members of the public commented federal regulations should
not override local ordinances. They noted the concern of local
authorities is safety, while others are concerned about industry costs.
They believe federal regulations that allow operators significant
discretion are a poor basis to supersede specific local requirements.
Response
    PHMSA appreciates these comments. Federal regulations provide for a
uniform body of standards and requirements related to pipeline safety.
PHMSA is receptive to input from state and local authorities on
pipeline safety issues. States and local authorities may adopt
requirements that are more stringent than and consistent with the
federal regulations for their intrastate pipelines if they have a 49
U.S.C. 60105 certification.
    13. One member of the public suggested regulations require periodic
safety audits by an auditor not selected by the pipeline operator. The
commenter further suggested that local authorities should have approval
authority in the choice of the auditor. The commenter contended this
approach would strengthen public confidence in pipeline safety.
Response
    PHMSA appreciates this comment. Highly trained federal and state
pipeline inspectors conduct inspections of pipeline operators, their
facilities, and their compliance programs on a regular basis.
Comments on ANPRM Section II Topics on Which PHMSA Sought Comment
    In section II of the ANPRM, commenters were urged to consider
whether additional safety measures are necessary to increase the level
of safety for those pipelines that are in non-HCA areas as well as
whether the current IM requirements need to be clarified and in some
cases enhanced to assure that they continue to provide an adequate
level of safety in HCAs. PHMSA posed specific questions to solicit
stakeholder input. These included questions related to the following
topics:
    A. Modifying the Definition of HCA,
    B. Strengthening Requirements to Implement Preventive and
Mitigative Measures for Pipeline Segments in HCAs,
    C. Modifying Repair Criteria,
    D. Improving Requirements for Collecting, Validating, and
Integrating Pipeline Data,
    E. Making requirements Related to the Nature and Application of
Risk Models More Prescriptive,
    F. Strengthening Requirements for Applying Knowledge Gained Through
the IM Program
    G. Strengthening Requirements on the Selection and Use of
Assessment Methods,
    H. Valve Spacing and the Need for Remotely or Automatically
Controlled Valves,
    I. Corrosion Control,
    J. Pipe Manufactured Using Longitudinal Weld Seams,
    K. Establishing Requirements Applicable to Underground Gas Storage,
    L. Management of Change,
    M. Quality Management Systems (QMS),
    N. Exemption of Facilities Installed Prior to the Regulations,
    O. Modifying the Regulation of Gas Gathering Lines.
    Each topic is summarized as presented in the ANPRM, then general
comments related to the topic are presented, followed by each
individual question and comments received for the question.

A. Modifying the Definition of HCA

    The ANPRM stated that ``IM requirements in subpart O of part 192
specify how pipeline operators must identify, prioritize, assess,
evaluate, repair and validate; [sic] through comprehensive analyses,
the integrity of gas transmission pipelines in HCAs. Although operators
may voluntarily apply IM practices to pipeline segments that are not in
HCAs, the regulations do not require operators to do so. A gas
transmission pipeline ruptured in San Bruno, California on September 9,
2010, resulting in eight deaths and considerable property damage. As a
result of this event, public concern has been raised regarding whether
safety requirements applicable to pipe in populated areas can be
improved. PHMSA is thus considering expanding the definition of an HCA
so that more miles of pipe are subject to IM 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 A
    1. INGAA and a number of pipeline operators noted this is an
opportune time for considering the next steps in integrity management,
since baseline assessments under the current IM rules are now being
completed. INGAA noted its policy goal is to apply IM principles

(as described in ASME/ANSI B31.8S) beyond HCAs, covering 90 percent of
people living near transmission pipelines by 2020 and 100 percent by
2030. TransCanada submitted information in support of INGAA's proposal,
noting that by the end of 2012 the company will have assessed more than
85 percent of its US pipeline mileage covering more than 95 percent of
people living near their pipelines. Thus, the current IM rules are
having a significant positive impact on pipeline safety. TransCanada
believes significant technological challenges would be encountered if
IM regulations were extended to all pipelines.
    2. MidAmerican commented it would be reasonable to differentiate
between transmission pipelines operating above and below 30 percent
specified minimum yield strength (SMYS) in terms of IM requirements.
They estimated that less than 3 percent of local distribution company
(LDC) transmission lines operate at greater than 30 percent SMYS.
    3. MidAmerican and a member of the public suggested PHMSA eliminate
class locations in favor of better-defined HCAs. They contend such a
change would result in administrative savings for pipeline operators.
    4. Southwest Gas and Paiute commented no new regulations should be
promulgated in this area until the study required by the Pipeline
Safety, Regulatory Certainty, and Job Creation Act of 2011 is
completed.
Response to General Comments for Topic A
    PHMSA appreciates the information provided by the commenters.
Section 5 of the Pipeline Safety, Regulatory Certainty, and Job
Creation Act of 2011 (the Act) (Pub. L. 112-90) requires the Secretary
of Transportation to ``evaluate (1) whether integrity management system
requirements, or elements thereof, should be expanded beyond high-
consequence areas; and (2) with respect to gas transmission pipeline
facilities, whether applying integrity management program requirements,
or elements thereof, to additional areas would mitigate the need for
class location requirements.'' PHMSA has completed the report mandated
by the Act that documents that evaluation and addresses whether
integrity management (IM) program requirements should be expanded
beyond high consequence areas (HCAs) and, specifically for gas
transmission pipelines regulated under 49 Code of Federal Regulations
(CFR) part 192, whether such expansion would mitigate the need for
class location designations and corresponding requirements. The class
location report is available for review in the docket.
    In October 2010 and August 2011, the Pipeline and Hazardous
Materials Safety Administration (PHMSA) published notices in the
Federal Register to solicit comments on revising the pipeline safety
regulations applicable to hazardous liquid and natural gas transmission
pipelines including expansion of IM program requirements beyond HCAs.
In general, industry representatives and pipeline operators were
opposed to any expansion of HCAs and in favor of eliminating class
locations on newly constructed pipelines, whereas public interest
groups were in favor of expanding HCA but against curtailing class
location requirements.
    PHMSA has carefully considered the input and comments. At this time
PHMSA plans to propose an approach that balances the need to provide
additional protections for persons within the potential impact radius
(PIR) of a pipeline rupture (outside of a defined HCA), and the need to
prudently apply IM resources in a fashion that continues to emphasize
the risk priority of HCAs. PHMSA, therefore, is considering an approach
that would require selected aspects of IM programs (namely, integrity
assessments and repair criteria) to be applicable for non-HCA segments.
For hazardous liquid pipelines, PHMSA would propose to apply these
requirements to non-HCA pipeline segments. For gas transmission
pipelines, PHMSA would propose to apply these requirements where
persons live and work and could reasonably be expected to be located
within a pipeline PIR. Under this approach, PHMSA would propose
requirements that integrity assessments be conducted, and that
injurious anomalies and defects be repaired in a timely manner, using
similar standards in place for HCAs. However, the other program
elements of a full IM program contained in 49 CFR part 192, subpart O,
or 49 CFR 195.452 (as applicable) would not be required for non-HCA
segments.
    The Act also required the Secretary of Transportation to evaluate
if expanding IM outside of HCAs, as discussed above, would mitigate the
need for class location requirements. In August 2013, PHMSA published a
notice in the Federal Register (78 FR 53086) soliciting comments on
expanding IM program requirements and mitigating class location
requirements. In addition, PHMSA held a Class Location Workshop on
April 16, 2014, to discuss the notice and comments were received from
stakeholders, including industry representatives, pipeline operators,
state regulatory agencies, and the public. Overall, the majority of
stakeholder responses suggested that PHMSA not change the current class
location approach for class locations and class location changes as
population increases used for establishing MAOP and operation and
maintenance (O&M) surveys for existing pipelines. For new transmission
pipelines, some industry groups and operators supported some type of
bifurcated approach for existing and new pipelines as described above.
    Based upon stakeholder input and findings from lessons learned,
incident investigations, assessments, IM, and operating, maintenance,
design and construction considerations, PHMSA believes the application
of integrity management assessment and remediation requirements to MCAs
does not warrant elimination of class locations. Class locations affect
all gas pipelines, including transmission (interstate and intrastate),
gathering, and distribution pipelines, whether they are constructed of
steel pipe or plastic pipe. Class location is integral to determining
MAOPs, design pressures, pipeline repairs, high consequence areas
(HCAs), and operating and maintenance inspections and surveillance
intervals. Class locations affect 12 subparts and 28 sections of 49 CFR
part 192 for gas pipelines. The subparts and sections are listed and
discussed in Sections <IP_ADDRESS> and <IP_ADDRESS>. While assessment and
remediation of defects on gas transmission pipelines is an important
risk mitigation program, it does not adequately compensate for other
aspects of class location as it relates to other types of gas pipelines
and as it relates (for all gas pipelines) to the original pipeline
design and construction such as the design factor, initial pressure
testing, establishment of MAOP, O&M activities, and other aspects of
pipeline safety, that are based on class location. Thus, PHMSA has
determined not to eliminate class location requirements.
    With respect to the application of gas transmission IM requirements
to pipeline operating at less than 30% SMYS, as part of its
consideration of the issues discussed in Topics J and N, PHMSA
considered but rejected the suggestion that pipelines operating less
than 30% SMYS be differentiated from those operating at higher stress
levels.
    Comments submitted for questions in Topic A.
    A.1--Should PHMSA revise the existing criteria for identifying HCAs
to expand the miles of pipeline included in HCAs? If so, what
amendments to the criteria should PHMSA consider (e.g.,

increasing the number of buildings intended for human occupancy in
Method 2?) Have improvements in assessment technology during the past
few years led to changes in the cost of assessing pipelines? Given that
most non-HCA mileage is already subjected to in-line inspection (ILI),
does the contemplated expansion of HCAs represent any additional cost
for conducting integrity assessments? If so, what are those costs? How
would amendments to the current criteria impact state and local
governments and other entities?
    1. INGAA, industry consultant Thomas Lael, and a number of pipeline
operators commented that modification of the HCA definition is
unnecessary. They contended that the current definition is already
risk-based and provides an effective basis for IM requirements along
with a reasonable point from which to expand the application of IM
principles by voluntary action. Accufacts commented that PHMSA should
focus on closing gaps and loopholes rather than increasing HCA mileage,
and that increasing covered mileage would only create the illusion of
more safety.
    2. AGA, APGA, and a number of gas distribution pipeline operators
also opposed changes to the definition. They commented that other
requirements of part 192 already address the primary threats for pipe
outside HCA. They noted that much effort went into establishing the
current definition, there is no safety rationale to abandon it, and
change would be inconsistent with risk-based principles and would
dilute safety efforts. AGA further noted that imprudent expansion would
be contrary to Congressional intent, in that it would dilute the focus
on densely populated and environmentally sensitive areas. AGA commented
that PHMSA should make no change in this area before completing the
related studies required by the Pipeline Safety, Regulatory Certainty,
and Job Creation Act of 2011.
    3. Taking a contrary position, a number of commenters not
affiliated with the pipeline industry supported increasing the pipeline
mileage classified as HCA. One private citizen suggested that all
pipelines in cities with population greater than 100,000 should be
classified as HCA. This commenter believes that existing regulations
result in insufficient requirements for urban pipelines. Another
citizen suggested that all high-stress lines with a ``receptor,'' which
he defines as ``something which needs to be protected,'' should be
assessed. If changes to the HCA definition are needed to accomplish
this, then he contended those changes should be made. The Pipeline
Safety Trust would strengthen IM requirements and expand them to all
transmission pipelines, although they allow that the details could be
different for pipelines not currently classified as HCA. PST believes
this would be an effective way to identify and eliminate threats.
    4. The Oklahoma Independent Petroleum Association (OKIPA) commented
that any changes to the HCA definition must be supported by a
scientifically-valid assessment of risks and a complete cost-benefit
analysis.
    5. The Iowa Association of Municipal Utilities commented that PHMSA
should not revise the HCA definition without taking into account the
differences between high-pressure transmission pipelines and low-
pressure, low-risk lines that are also classified as transmission. IAMU
reported ``transmission lines'' operated by Iowa Municipal Utilities
are typically 2 to 4 inches in diameter and have potential impact radii
less than 90 feet.
    6. The Texas Pipeline Association and Texas Oil & Gas Association
contended that expanding HCA pipeline mileage would increase assessment
costs, particularly if the arbitrary requirement for reassessments
every 7 years is not changed. These associations also believe that
additional assessments will result in significant service
interruptions. They suggested that assessment requirements be expanded
to other pipelines, if needed, rather than changing the definition of
HCA, contending that this would allow a more reasoned approach not
burdened by the requirement for 7-year reassessments.
    7. The Texas Pipeline Association, Texas Oil & Gas Association and
several pipeline operators disagreed with the ANPRM assertion that most
non-HCA transmission pipeline has been subject to ILI inspections. They
noted much non-HCA pipeline has been pigged (i.e., assessed using an
in-line inspection tool) but that intrastate transmission pipelines are
typically not piggable.
    8. MidAmerican suggested that there is no reason to believe that
changes to the HCA definition would improve safety. They also noted
that the effects of other recent regulatory changes have not yet been
realized and could mask any effect of changes in HCA. At the same time,
the company noted that revising the definition of an HCA to encompass
potential impact circles with 15 structures intended for human
occupancy, vs. the current 20, would increase the amount of HCA mileage
on its pipeline system by about 10 percent, contending that the safety
benefit of such a change would be questionable. They suggested it would
be better to focus on pipe in HCAs rather than adding lower-risk pipe,
since part 192 already provides a good level of safety for all
pipelines.
    9. INGAA and a number of pipeline operators commented that
increasing the amount of HCA mileage would add or increase costs for
hundreds of state and local government agencies. The increases would
result from increased demands for identification, certification, and
compliance auditing.
    10. Northern Natural Gas suggested that PHMSA consider expanding
HCA coverage by modifying the specifics of Method 2 for defining HCAs
over time. Changes could include reducing the number of structures in
potential impact circles that define an HCA, reducing the number of
people that defines an identified site, etc. The company believes this
kind of change would have the benefit of continued use of the
``science'' represented by the C-FER Technologies circle for
determining HCAs (see part 192, appendix E, figure E.I.A). Northern
also suggested PHMSA define a time period for occupation of an
identified site which, they contended, would eliminate the need to
address locations where a gathering of people is truly transient.
    11. TransCanada reported its belief that the current HCA criteria
provide an appropriate risk focus. In support of this belief, they
noted that only 3 percent of their US transmission pipeline mileage is
in HCAs but this includes 45 percent of the population within a
potential impact radius of their pipelines.
    12. The Iowa Utilities Board opposed changes to the HCA criteria to
encompass more mileage. IUB commented that such changes would divert
resources from application to higher-risk pipeline segments and there
has been no demonstration that non-HCA pipeline segments pose as much
risk as those currently defined as HCA.
    13. Two private citizens and the Commissioners of Wyoming County,
Pennsylvania, suggested the existence of one structure intended for
human occupancy within a potential impact circle should be sufficient
to define an HCA. These commenters noted that catastrophic consequences
(i.e., loss of life) are still possible in such sparsely populated
areas. The Commissioners noted homes in their jurisdiction generally
did not encroach on the pipelines; the homes were there first and the
pipeline encroached on what should have been a safe zone around the
home. They implied pipeline operators should expect a higher burden to
assure safety in such circumstances.

    14. The Pipeline Safety Trust commented that there should be a
single set of criteria defining HCAs and that these criteria should be
known to the public. They contended the public currently has no
information on the criteria defining HCAs.
    15. The California Public Utilities Commission commented that HCA
criteria should be revised to include more pipeline mileage and that
method 2 (use of potential impact circles) should be eliminated.
    16. The Alaska Natural Gas Development Authority suggested that the
definition of an HCA should accommodate the phenomenon of rapid growth
in previously rural areas. They noted that such growth has occurred
within Alaska due, in part, to disposal of state lands.
    17. NAPSR suggested that PHMSA require all transmission pipelines
to meet Class 3 and 4 requirements and eliminate HCAs. NAPSR contended
that focusing resources on higher-risk pipelines is bad public policy,
since an accident anywhere poses a risk to public safety and reduces
public confidence.
    18. The Texas Pipeline Association, Texas Oil & Gas Association and
several pipeline operators objected to the implication in the ANPRM
that assessment costs have decreased. They contended that costs have
actually increased due to such factors as operational cost escalation
and increased costs to address cased pipeline segments.
    19. INGAA and a number of pipeline operators contended that costs
cannot be estimated accurately absent a specific regulatory proposal.
They suggested that additional costs would be minimal if expanding HCA
mileage results in actions similar to INGAA's Integrity Management--
Continuous Improvement (IMCI) action plan, but that costs could be high
if different requirements are imposed.
    20. INGAA reported that a recent survey showed that its members'
identified baseline IM assessments will cover 64 percent of members'
pipeline mileage, only 4 percent of which is in HCAs. INGAA stated that
these assessments will have covered 90 percent of the population within
a potential impact radius of the pipelines.
    21. Southwest Gas and Paiute provided cost estimates for conducting
IM assessments on their pipeline systems: $45,000 per mile for direct
assessment, up to $125,000 per mile for in-line inspection, and from
$200,000 to $2 million per instance where changes need to be made to a
pipeline to accommodate instrumented pigs.
    22. The California Public Utilities Commission and MidAmerican
commented that costs would increase if the changes suggested in the
ANPRM were made, but they provided no specific estimates.
    23. APGA noted that costs incurred by or passed on to municipal
utilities are costs to local governments, since the utilities are,
themselves, government agencies.
    24. Paiute and Southwest Gas noted that costs to local governments,
including preparation of permits, paving repairs, etc., can be high.
    25. An anonymous commenter suggested that costs are not likely to
increase much, since most operators already assess more than HCAs and
IM has fostered growth in ILI vendors.
    26. Kern River noted that its costs would not increase much, since
the company is already under similar restrictive requirements via
special permit.
    27. Accufacts noted that safety is not free. They suggested that
relative ranking of assessment methods, by cost, is not likely to have
changed. They cautioned that costs used in cost-benefit analyses
supporting any rules must be credible and should have an auditable
trail available to the public. They suggested that serious accidents
can be a ``cost'' of associated deregulation and lack of proper,
effective, and efficient safety regulatory oversight for this critical
infrastructure.
Response to Question A.1 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA
agrees that the definition of HCAs is adequate, and does not propose to
modify the definition of scope of HCAs in this proposed rulemaking.
However, to afford additional protections to other segments along the
pipeline, PHMSA is proposing to apply selected IM program elements
(namely assessment and remediation of defects) to areas outside HCAs
that are newly defined as MCAs. PHMSA believe this approach applies
appropriate risk-based levels of safety.
    A.2. Should the HCA definition be revised so that all Class 3 and 4
locations are subject to the IM requirements? What has experience shown
concerning the HCA mileage identified through present methods (e.g.,
number of HCA miles relative to system mileage or mileage in Class 3
and 4 locations)? Should the width used for determining class location
for pipelines over 24 inches in diameter that operate above 1000 psig
be increased? How many miles of HCA covered segments are Class 1, 2, 3,
and 4? How many miles of Class 2, 3, and 4 pipe do operators have that
are not within HCAs?
    A.3. Of the 19,004 miles of pipe that are identified as being
within an HCA, how many miles are in Class 1 or 2 locations?
    1. Industry trade associations, pipeline operators, and the Iowa
Utilities Board objected to the suggestion all Class 3 and 4 locations
should be treated as HCA. They noted class location does not have a
direct relationship to risk. Small, low-pressure pipelines with no
structures intended for human occupancy within the PIR (or for which
the PIR is contained entirely within the right of way) could be Class 3
or 4 under current definitions. INGAA noted approximately 90 percent of
Class 3 and 4 mileage not in HCA is presently assessed through over
testing during IM assessments. Kern River commented that class location
is an outmoded system that is confusing and unduly complex. Many of
these commenters noted there is no demonstration of need for including
all Class 3 and 4 areas, since existing HCA criteria adequately
identify areas posing higher risks.
    2. Public commenters took a contrary position, suggesting class
locations are a reasonable basis for increasing HCA mileage. Pipeline
Safety Trust and California Public Utilities Commission commented all
Class 3 and 4 locations should be HCA. They noted these are all highly
populated areas putting more people at risk from pipeline accidents.
CPUC noted the location of the significant 2010 pipeline accident in
San Bruno, CA, could have avoided HCA classification if method 2 of the
current definition had been used. An anonymous commenter supported this
position, suggesting all Class 3 and 4 locations be treated as HCA and
use of method 2 be restricted to Class 1 and 2 locations; this
commenter contended use of method 2 to exclude some portions of Class 3
and 4 locations from HCA classification is inappropriate. This
commenter further suggested the definition of Class 4 locations be
revised, contending that the criterion of 4-story buildings being
``prevalent'' is not specific enough. Thomas Lael, an industry
consultant, suggested all Class 4 locations should be HCA. Lael
contended that this would be an easy change and would assure that the
highest risk pipe is included.
    3. NAPSR also suggested all Class 3 and 4 locations should be
classified as HCA. NAPSR noted this is an alternative to their
preferred solution of eliminating HCA and requiring that all
transmission pipelines meet Class 3 and 4 requirements.

    4. One public commenter went further. He suggested a new
classification, Class 5, be established encompassing all pipeline in
cities with populations of more than 100,000. He further suggested pipe
in this new class should meet enhanced construction requirements,
including required installation of automatic valves to isolate the
pipeline in the event of an incident. He contended the existing
regulations impose inadequate safety requirements on urban pipelines.
    5. Accufacts suggested PHMSA focus first on closing loopholes and
gaps rather than increasing HCA mileage. They commented increasing
covered mileage without closing gaps would produce only the illusion of
safety.
    6. Northern Natural Gas suggested PHMSA consider an option of
eliminating method 2 of the current HCA definition. They contended such
a change would be easy to accomplish. At the same time, they questioned
its efficacy, suggesting that it would result in limited or no increase
in safety while imposing large costs.
    7. INGAA and many pipeline operators objected to the suggested
increase in the width of a class location unit for larger, high-
pressure pipelines. They noted such a change would contravene the goals
of IM and divert resources to pipe of lower risk, and pipe of this type
posing high risks to population concentrations is already included as
HCA based on its potential impact radius (which could be larger than
220 yards).
    8. Here, again, public commenters generally took a contrary
position. Pipeline Safety Trust suggested class location width should
be at least as much as the potential impact radius. PST noted the PIR
is intended to focus on areas requiring more protection while the
existing class location width is arbitrary. Two private citizens
agreed, one noting that large-diameter, high-pressure gathering
pipelines in the Marcellus shale area are located slightly more than
220 yards from pre-existing houses and the other suggesting the class
location width in higher-class areas should be 220 yards or the PIR,
whichever is larger. Accufacts would go further, suggesting class
location width be increased for large-diameter pipe regardless of
pressure. Accufacts contended diameter is a more significant factor in
determining the potential extent of post-accident damage than is
pressure, noting the devastation resulting from the San Bruno accident
extended to a much greater distance than the PIR. The Texas Pipeline
Association and Texas Oil & Gas Association commented no change should
be made until the studies required by the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011 are completed.
    9. INGAA and a number of pipeline companies submitted data
concerning the amount of pipeline mileage currently in HCAs. INGAA's
data is based on a survey of its members.

----------------------------------------------------------------------------------------------------------------
                          INGAA              Paiute             SWGas           MidAmerican     Northern Natural
----------------------------------------------------------------------------------------------------------------
Class 1...........  475 miles HCA,     1 mile HCA, 632    <1 of 382 miles    0.63 miles HCA,    0.1% of all
                     103,286 not.       not.               are HCA.           493.11 not.        mileage is HCA.
Class 2...........  535 miles HCA,     0 miles HCA, 55    <1 of 20 miles     0.98 miles HCA,    2% of mileage is
                     11,318 not.        not.               are HCA.           101.92 not.        HCA.
Class 3...........  4,100 miles HCA,   26 miles HCA, 142  185 miles HCA,     44.96 miles HCA,   27% of mileage
                     4, 646 not.        not.               242 not.           128.38 not.        is HCA.
Class 4...........  24 miles HCA, 5    None of less than  6 miles HCA, 5     no HCA mileage...  no data
                     not.               1 mile is HCA.     not.                                  reported.
----------------------------------------------------------------------------------------------------------------

    10. Iowa Association of Municipal Utilities reported its members
have zero HCA miles in any class. Most member transmission pipelines
are in Class 1 locations. Members have 1.46 miles of Class 2 pipe and
one mile in Class 3.
    11. Ameren Illinois reported 3.5 of its 82 HCA miles are in Class 1
or 2.
    12. Kern River reported it has 18.51 HCA miles in Class 1 and 3.14
miles in Class 2, of a total of 95.96 miles of HCA.
    13. On March 15, 2012, PHMSA received a petition for rulemaking
from the Jersey City Mayor's office contending that the current Class
Location system ``does not sufficiently reflect high density urban
areas, as the regulation fails to contemplate either (1) the dramatic
differences in population densities between highly congested areas and
other less dense Class 4 Locations, or (2) the full continuum of
population densities found in urban areas themselves.'' Based on this,
Jersey City petitioned PHMSA to add three (3) new Class Locations,
which would be defined as follows:
     A Class 5 location is any class location unit that
includes one or more building(s) with between four (4) and eight (8)
stories;
     A Class 6 location is any class location unit that
includes one or more building(s) with between nine (9) and forty (40)
stories;
     A Class 7 location is any class location unit that
includes at least one building with at least forty-one (41) stories.
Response to Questions A.2 and A.3 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA
agrees that HCAs should not be based exclusively on class location.
Similarly, PHMSA does not propose to define MCAs based on class
location. PHMSA proposes that moderate consequence area means an
onshore area that is within a potential impact circle, as defined in
Sec.  192.903, containing five (5) or more buildings intended for human
occupancy, an occupied site, or a right-of-way for a designated
interstate, freeway, expressway, and other principal 4-lane arterial
roadway as defined in the Federal Highway Administration's Highway
Functional Classification Concepts, Criteria and Procedures, and does
not meet the definition of high consequence area, as defined in Sec.
192.903. This assures a comparable level of safety for all pipelines,
regardless of class location. As a result, PHMSA is not proposing to
expand class locations in this proposed rule. The issue of expanding
class locations is addressed in the class location report which is
available for review in the docket while formulating comments.
    A.4. Do existing criteria capture any HCAs that, based on risk, do
not provide a substantial benefit for inclusion as an HCA? If so, what
are those criteria? Should PHMSA amend the existing criteria in any way
which could better focus the identification of an HCA based on risk
while minimizing costs? If so, how? Would it be more beneficial to
include more miles of pipeline under existing HCA IM procedures, or, to
focus more intense safety measures on the highest risk, highest
consequence areas or something else? If so why?
    1. INGAA and several pipeline operators commented the method
described in paragraph 2 in the

definition of HCA in Sec.  192.903 appropriately focuses attention on
at-risk populations. They contended that the method described in
paragraph 1 in the definition of HCA in Sec.  192.903 captures some
inappropriate areas.
    2. Texas Pipeline Association, Texas Oil & Gas Association, and
Ameren Illinois contended the existing criteria do not capture areas
not posing risk. They noted the criteria were based on the science of
pipeline accidents to identify high-risk areas.
    3. Paiute and Southwest Gas commented neither more HCA miles nor
additional safety measures are needed. They contended existing criteria
are adequate and rule provisions for preventive and mitigative measures
and to consider pipe with similar conditions when anomalies are found
in HCA are sufficient to address non-HCA pipeline segments.
    4. APGA recommended the regulations be modified to treat
transmission pipelines operated by local distribution companies, most
of which operate at less than 30 percent SMYS, under distribution
integrity management rather than transmission IM. APGA suggested this
is an optimum time to make this change, which was discussed in the
phase 1 work leading up to the distribution IM rule. Atmos agreed,
noting failure by leakage rather than rupture, similar to distribution
pipelines, is much more prevalent for this low-stress pipeline and it
thus poses much lower risks.
    5. Northern Natural Gas suggested PHMSA revisit its treatment of
``well defined areas'' that constitute identified sites. They contended
current practice treats an entire area as an identified site even if
only an unoccupied corner is within the PIR and persons congregating
are outside that critical radius.
    6. MidAmerican suggested PHMSA consider adding a multiplier to the
PIR equation for higher-stress pipelines. They contended this could
capture more high-risk pipe without adversely affecting low-stress
pipelines that pose considerably less risk.
    7. Atmos commented no change should be made which would increase
the amount of HCA mileage, contending that this would dilute the
current focus on high-risk pipe.
    8. INGAA and several of its members suggested PHMSA rely on its
Integrity Management--Continuous Improvement (IMCI) initiative to
address pipeline in non-HCA areas.
Response to Question A.4 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA
agrees that the existing method for identifying HCAs and calculating
PIR is appropriate and is not proposing a change to either. However,
PHMSA disagrees that existing requirements are sufficient for non-HCAs
segments. PHMSA believes non-HCA segments where people congregate
should be afforded additional protections. Therefore, PHMSA is
proposing that selected IM program elements (assessment and remediation
of defects) be applied to MCAs.
    A.5. In determining whether areas surrounding pipeline right-of-
ways meet the HCA criteria as set forth in part 192, is the potential
impact radius sufficient to protect the public in the event of a gas
pipeline leak or rupture? Are there ways that PHMSA can improve the
process of right-of-ways HCA criteria determinations?
    1. INGAA, AGA, GPTC and a number of pipeline operators contended
the existing PIR criteria are sufficiently conservative. They noted the
criteria were derived from scientific analysis of the consequences of
past pipeline accidents. Texas Pipeline Association and Texas Oil & Gas
Association commented there is no reason to modify the PIR criteria or
to establish alternate criteria to define HCAs; they contended there is
no evidence the current PIR definition has provided insufficient
protection to the public.
    2. One private citizen and Alaska's Department of Natural Resources
suggested HCA criteria should be revised to consider parallel pipelines
in a common right of way, contending that an accident on one pipeline
could impact adjacent lines, thus compounding consequences. They
further suggested requirements for pipelines in common rights of way
should include minimum spacing between the pipelines.
    3. An anonymous commenter suggested plume releases be considered to
determine which pipeline segments can affect an HCA, contending that
this would be a good practice.
    4. AGA, Texas Pipeline Association, Texas Oil & Gas Association,
GPTC, and several pipeline operators cautioned against use of the term
``right of way'' in the context of defining HCAs. They noted this term
is imprecise and the actual location of the pipeline, rather than an
ill-defined right of way, is the important factor in evaluating risk.
    5. Accufacts, INGAA, and numerous pipeline operators cautioned
against discussions that imply that the PIR concept is applicable to
considerations of risk from pipeline leaks. These commenters noted that
the PIR is based on the consequences of a pipeline rupture and
resulting conflagrations and was never intended to address leaks not
involving fires.
    6. ITT Exelis Geospatial Systems, a company providing services to
the pipeline industry, noted accurate location of a pipeline is as
important to assuring adequate protection of high-risk populations as
is the calculation of PIR.
    7. Accufacts suggested PHMSA require a report of the actual impact
area, including aerial photographs, within 24 hours of any pipeline
rupture. Accufacts contended this data would provide a further basis
for continuing review of PIR adequacy.
Response to Question A.5 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA
agrees that the existing definition of PIR is appropriate at this time.
PHMSA believes that adjusting the PIR formula based on parallel
pipelines in the right-of-way, or other right-of-way factors, are
premature at this time. Also, PHMSA acknowledges that the PIR approach
only applies such incidents resulting in explosions and fires. While
certain gases might be better modeled using plume models, such models
have not been carefully studied or developed. However, PHMSA plans to
pursue (outside the scope of this rulemaking) additional incident
reporting requirements for the purpose of further evaluating the extent
of damage following incidents.
    A.6. Some pipelines are located in right-of-ways also used, or
paralleling those, for electric transmission lines serving sizable
communities. Should HCA criteria be revised to capture such critical
infrastructure that is potentially at risk from a pipeline incident?
    1. INGAA, AGA, Texas Pipeline Association, Texas Oil & Gas
Association, and many pipeline operators objected to any potential
inclusion of ``critical infrastructure'' in HCA criteria. They noted
there is no history of problems caused by impacts on infrastructure,
there is little public risk involved, data regarding such
infrastructure would be difficult for pipeline operators to obtain, and
issues involving potential interactions with critical infrastructure
are usually addressed during pipeline planning and construction.
    2. GPTC and Nicor recommended HCA criteria not be revised to
include critical infrastructure. They noted the intent of defining HCAs
is to address risk to life and not property damage and damages to local
infrastructure are unlikely to result in consequences similar to those
that could affect population concentrations near the

pipeline. Atmos agreed, noting planning for accident-caused outages is
a responsibility of electric system operators.
    3. Pipeline Safety Trust, Accufacts, NAPSR, Alaska Department of
Natural Resources, California Public Utilities Commission and ITT
Exelis Geospatial Systems recommended critical infrastructure be
included among HCA-defining criteria. Several of these commenters
suggested infrastructure beyond electric transmission be considered,
including, for example, water and sewage treatment plants, fire
stations, and communications facilities. The commenters noted damages
to critical infrastructure can lead to cascading effects and additional
public safety consequences. ITT Exelis acknowledged these
considerations may be secondary to loss of life but contended they are
still important to public safety.
    4. Northern Natural Gas, Kern River, MidAmerican, Paiute, and
Southwest Gas noted determining the impact of damages to infrastructure
items is complex. These commenters suggested it is not practical to
define what constitutes ``critical'' infrastructure, from a public
safety standpoint, on a generic basis. They recommended PHMSA leave
consequence determination to operators, as part of their risk
assessments, providing additional guidance for such considerations if
needed.
    5. An anonymous commenter suggested more frequent tests of cathodic
protection and coating surveys be required in areas potentially subject
to induced currents from nearby electric transmission infrastructure.
Response to Question A.6 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA
agrees that there have been relatively few pipeline incidents that have
had a major impact on critical infrastructure. PHMSA also acknowledges
that the PIR formula was developed based on life safety (i.e., heat
flux that result in fatalities). However, PHMSA is also aware of recent
incidents that, among other consequences, damaged and caused temporary
closure of interstate highways. Among them are the 2012 incident at
Sissonville, WV and the 2010 incident at New Delhi, LA, which also
resulted in one fatality. Even though PHMSA is not proposing to revise
the HCA criteria or the PIR formula, PHMSA is proposing to include
major highways in the MCA criteria.
    A.7. What, if any, input and/or oversight should the general public
and/or local communities provide in the identification of HCAs? If
commenters believe that the public or local communities should provide
input and/or oversight, how should PHMSA gather information and
interface with these entities? If commenters believe that the public or
local communities should provide input and/or oversight, what type of
information should be provided and should it be voluntary to do so? If
commenters believe that the public or local communities should provide
input, what would be the burden entailed in providing provide this
information? Should state and local governments be involved in the HCA
identification and oversight process? If commenters believe that state
and local governments be involved in the HCA identification and
oversight process what would the nature of this involvement be?
    1. INGAA and its pipeline operator members commented no additional
public involvement is needed. INGAA noted consultation is required
under the current regulations, and it seldom identifies any relevant
information. Additional involvement, INGAA contends, would likely lead
to inconsistencies and would degrade the technical/scientific basis for
determining HCAs.
    2. AGA and several of its member companies suggested local
government agencies should provide information when requested by
pipeline operators. They contended additional required involvement
would pose an additional burden on pipeline operators while adding no
benefit. AGA noted information from its members suggests that local
government agencies very rarely point out identified sites not
otherwise known to the pipeline operator.
    3. Texas Pipeline Association, Texas Oil & Gas Association, GPTC,
Nicor, Ameren Illinois and Oleksa and Associates (a pipeline industry
consultant) suggested further involvement of local governments not be
required. These commenters contended pipeline operators have more
relevant knowledge and involvement of inexperienced entities in
identifying HCAs is more likely to result in confusion than useful
information. The Texas associations suggested current public awareness
requirements afford sufficient involvement of local agencies.
    4. Accufacts noted local governmental agencies have maps
identifying locations important to public safety and suggested these
maps should be used by pipeline operators in HCA determinations.
Accufacts believes this could assist operators in assuring
consideration of accurate, complete, and current information.
    5. Northern Natural Gas reported it has a phone number and email
address that local residents and agencies can use to provide input to
its HCA determinations. Northern further reported no HCAs have been
identified from information provided via these avenues that were not
otherwise known to the company.
    6. Public commenters suggested local residents and government
agencies should receive more information concerning pipelines and HCAs.
One commenter suggested operators should provide copies of IM plans
upon request, and should provide prior notification to residents within
a PIR of assessments and a subsequent report of assessment results or
problems otherwise identified. This individual also suggested locations
of HCAs and assessment trend results should be provided to local
communities upon request. The League of Women Voters of Pennsylvania
suggested distribution integrity management plans should be readily
available and the public should be involved in decisions related to
those plans.
    7. Pipeline Safety Trust commented public review should be part of
any process by which PHMSA reviews or approves of HCA identifications.
    8. Wyoming County Pennsylvania Commissioners suggested stakeholder
meetings and public comment periods be required as part of HCA
identification. They noted local residents know their communities
better than others, including expected changes that could affect HCA
identification.
    9. AGA and several of its member operators recommended local
governments play no role in oversight of HCA determinations. They
contended this would increase burden and result in inconsistencies and
confusion.
    10. An anonymous commenter suggested existing public awareness
contacts should be used to improve HCA determinations. The commenter
expressed the belief this existing structure could allow low-cost
involvement of local officials in such determinations.
    11. The NTSB suggested PHMSA work with states to employ oversight
of pipeline IM plans based on objective metrics. The NTSB noted this
would be consistent with recommendation P-11-20 resulting from its
investigation of the San Bruno, CA pipeline accident.
    12. Iowa Association of Municipal Utilities noted local government
employees are involved when HCA determinations are made by municipal
utilities and further requirements for

local involvement would be inappropriate for such operators.
Response to Question A.7 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA
is continuing to evaluate this aspect of integrity management but has
not yet reached any conclusions. PHMSA may consider this input for
future action, if applicable.
    A.8. Should PHMSA develop additional safety measures, including
those similar to IM, for areas outside of HCAs? If so, what would they
be? If so, what should the assessment schedule for non-HCAs be?
    1. Pipeline operators and their associations generally agreed
additional measures were not needed outside HCA. INGAA and several
transmission pipeline operators suggested operators be allowed to apply
the principles of ASME/ANSI B31.8S voluntarily, as needed. INGAA noted
this is the concept behind its Integrity Management--Continuous
Improvement (IMCI) initiative.
    2. AGA and a number of its member operators noted the regulations
already require implementation of preventive and mitigative measures
outside of HCA for low-stress pipe (Sec.  192.935(d)). These
requirements include using qualified personnel to conduct work that
could adversely affect the integrity of the covered segment, collecting
excavation damage information, and participating in one-call systems.
    3. Ameren Illinois and MidAmerican commented additional measures
are not needed, because existing operations & maintenance requirements
already assure integrity.
    4. GPTC and Nicor agreed, noting it would be inappropriate to apply
IM measures outside of HCA and existing requirements are assuring an
adequate level of safety.
    5. Atmos contended the existing provision requiring that operators
evaluate and remediate non-HCA pipeline segments when corrosion is
found during an IM assessment of a covered pipeline segment (Sec.
192.917(e)(5)) already provides that actions be taken to assure the
integrity of non-HCA pipeline segments.
    6. Texas Pipeline Association and Texas Oil & Gas Association would
not object to a phased expansion of IM requirements provided that
required assessment intervals are scientifically based. The
associations noted Texas pipelines are already subject to the broader
requirements of the Texas IM rule. They commented phased implementation
would assure the next-highest risks are addressed first and would allow
time for IM-support resources to grow.
    7. Iowa Association of Municipal Utilities commented new
requirements are not needed for its members' pipelines. These lines are
small-diameter, low-pressure, odorized, and already pose low risk.
    8. Northern Natural Gas suggested PHMSA expand the HCA definition
gradually over time rather than imposing IM requirements outside HCA.
Northern commented such an approach would retain and expand the focus
on areas posing the highest risk.
    9. Accufacts commented repair criteria, including required response
times, and reporting of anomalies should be the same in- or outside
HCA, since the progression of an anomaly to failure is unrelated to
whether the anomaly exists within or outside of an HCA.
    10. Pipeline Safety Trust suggested non-HCA pipeline segments
should be subject to a baseline of IM requirements.
    11. The Commissioners of Wyoming County Pennsylvania suggested
PHMSA consolidate operators' best practices and require assessment of
all pipe frequently enough to realize a benefit. They commented this
approach would assure a consistent level of public protection
regardless of the practices of individual pipeline operators.
    12. California Public Utilities Commission noted this question
would be moot if method 2 for defining HCA is eliminated.
Response to Question A.8 Comments
    PHMSA appreciates the information provided by the commenters.
Although most industry commenters did not support expansion of
integrity management requirements outside HCAs, PHMSA believes
additional protections are needed for pipeline segments where people
are expected within the PIR. In this NPRM, PHMSA proposes an approach
that balances the need to provide additional protections for persons
within the potential impact radius (PIR) of a pipeline rupture (outside
of a defined HCA), and the need to prudently apply IM resources in a
fashion that continues to emphasize the risk priority of HCAs. The
proposed regulation would require selected aspects of IM programs
(namely, integrity assessments and repair criteria) to be applicable
for selected non-HCA segments defined as MCAs. An MCA would be a
segment located where persons live and work and could reasonably be
expected to be located within a pipeline PIR. PHMSA would propose
requirements that integrity assessments be conducted, and that
injurious anomalies and defects be repaired in a timely manner, using
similar standards in place for HCAs. However, the other program
elements of a full IM program contained in 49 CFR part 192, subpart O
would not be required for MCA segments.
    A.9. Should operators be required to submit to PHMSA geospatial
information related to the identification of HCAs?
    1. Most industry commenters, including INGAA, AGA, and numerous
pipeline operators supported this proposed requirement. They noted
submission of this data will be required for PHMSA to comply with the
mapping provisions of the Pipeline Safety, Regulatory Certainty, and
Job Creation Act of 2011.
    2. Accufacts, Alaska Department of Natural Resources, California
Public Utility Commission, and one private citizen agreed, suggesting
PHMSA should know where HCAs are located and that this information is
important to emergency responders. CPUC also suggested operators should
be required to submit this information to State regulatory authorities
as well.
    3. Pipeline Safety Trust also supported this proposal, adding the
information should be shared with the public.
    4. League of Women Voters of Pennsylvania and Accufacts also
supported making maps identifying pipeline locations, including HCA,
available to the public.
    5. Atmos, Northern Natural Gas, Kern River, Nicor, and GPTC opposed
a requirement to submit this information. They noted this is a large
amount of information which is available for audits and questioned how
it would be used by PHMSA and how related security issues would be
addressed.
    6. Ameren Illinois suggested a requirement to submit HCA locations
is not needed, since location data on the entire pipeline system must
already be submitted to the National Pipeline Mapping System.
    7. Texas Pipeline Association, Texas Oil & Gas Association, and
MidAmerican agreed that providing HCA information as part of NPMS
submissions is adequate. They noted this is consistent with Section 6
of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of
2011.
Response to Question A.9 Comments
    PHMSA appreciates the information provided by the commenters. Most
commenters supported the submittal of HCA information in geospatial
format. As noted by one commenter, this is required by the Act.
Although outside

the scope of this rulemaking, PHMSA is pursuing data reporting
improvements by proposing revisions to its currently approved
information collection for the National Pipeline Mapping System. PHMSA
has published several Federal Register notices and held several public
workshops on the proposals.
    A.10. Why has the number of HCA miles declined over the years?
    1. Responses to this question consisted of speculation regarding
reasons why the number of HCA miles may have declined. No commenters
reported having specific data to describe the reducing trend.
    2. AGA suggested pipe replacement, reductions in MAOP, and use of
better data could be among the many reasons for a decline in HCA
mileage.
    3. INGAA speculated the reduction could be a result of operators
changing from method 1 to method 2 to identify HCAs and abandoning or
retiring older pipelines.
    4. Texas Pipeline Association, Texas Oil & Gas Association, Atmos,
and a private citizen agreed a change in the method for identifying
HCAs is a likely reason for the decreasing mileage trend.
    5. Northern Natural Gas commented changes in land use over time
result in changes in the pipeline segments identified as HCA. Northern
noted it has changed from method 1 to method 2 for identifying HCA but
that the change had resulted in an increase in HCA mileage rather than
a decrease. Kern River also reported that its HCA mileage is
increasing, citing changes in land use along the pipeline as the reason
for this change.
    6. GPTC and Nicor suggested operational changes and removal of pipe
from service could be the cause of the observed changes.
    7. Iowa Utilities Board noted reductions in pressure and other
operational changes can eliminate covered pipeline segments. IUB also
suggested a change from method 1 to method 2 and better analyses of
potential impact circles, etc. could have resulted in decreased HCA
mileage.
    8. MidAmerican noted its HCA mileage has fluctuated but remains
relatively constant overall. They noted periodic fluctuations result
from changes in various parameters that go into identifying HCAs.
    9. A private citizen suggested operators may be buying properties
within potential impact circles and razing them or that new pipelines
in rural areas may be replacing current pipelines.
    10. An anonymous commenter suggested HCA mileage is decreasing
because operators are getting better at identifying HCAs. The commenter
noted operators have been doing so for 9 years.
Response to Question A.10 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA
considered this input in its evaluation mandated by the Act.
    A.11. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible.
    1. Accufacts commented property damage costs reported to PHMSA
following pipeline incidents appear to be understated. Accufacts noted
this raises serious questions about the validity of cost-benefit
analyses performed using this data.
    2. Iowa Association of Municipal Utilities commented the costs to
comply with IM-like requirements are not justified for small, low-
pressure transmission pipelines such as those operated by its members.
Significant costs to develop IM plans, evaluate remote valves, and
comply with other IM requirements must be passed on to a small rate
base for many municipal utilities.
    3. ITT Exelis Geospatial Systems suggested HCA criteria be revised
and requirements for protection of critical infrastructure and
populated areas be made more prescriptive. They commented such changes
would require that leak surveys be performed more frequently, providing
improved safety.
    4. ITT Exelis Geospatial Systems reported its leak detection
systems, developed as part of research jointly sponsored with DOT and
other agencies, could facilitate this testing and initial costs would
be offset by longer term savings.
    5. California Public Utilities Commission observed the public has
indicated its desire for more prescriptive safety requirements.
Response to Question A.11 Comments
    The Act requires that the Secretary of Transportation to evaluate
whether integrity management requirements should be expanded beyond
HCAs and whether such expansion would mitigate the need for class
location requirements. The proposed rulemaking does not change the HCA
definition. However, PHMSA is proposing pipeline assessment
requirements in new Sec.  192.710 for newly defined moderate
consequence areas (MCAs). PHMSA is also proposing new requirements in
Sec.  192.607 for verification of pipeline material and Sec.  192.624
for MAOP verification would also apply to MCAs. PHMSA performed a
Preliminary Regulatory Impact Analysis, using the best available data
and information. It is available on the docket and PHMSA invites
comments on the PRIA.

B. Strengthening Requirements To Implement Preventive and Mitigative
Measures for Pipeline Segments in HCAs

    Section 192.935 requires gas transmission pipeline operators to
take additional measures, beyond those already required by part 192, to
prevent a pipeline failure and to mitigate the consequences of a
potential failure in a HCA following the completion of a risk
assessment. Section 192.935(a) specifies examples of additional
measures, which include, but are not limited to installing automatic
Shut-off Valves or Remote Control Valves; installing computerized
monitoring and leak detection systems; replacing pipe segments with
pipe of heavier wall thickness; providing additional training to
personnel on response procedures; conducting drills with local
emergency responders; and implementing additional inspection and
maintenance programs. In the ANPRM, PHMSA expressed concern that these
additional measures are not explicitly required. As a result, operators
may not be employing the appropriate additional measures as intended.
Section 192.935(b) specifies that operators are also required to
enhance their damage prevention programs and to take additional
measures to protect HCA segments subject to the threat of outside force
damage (non-excavation). PHMSA also noted in the ANPRM that the
provisions in Sec.  192.935 only apply to HCAs and that the expansion
of the HCA definition would increase the mileage of pipelines subject
to Sec.  192.935. Further, PHMSA acknowledged the consideration of
expanding preventive and mitigative measures to pipelines outside of
HCAs. The following are general comments received related to the topic
as well as comments related to the specific questions:
General Comments for Topic B
    1. INGAA suggested PHMSA can substantially improve prevention and
mitigation of accidents caused by excavation damage by facilitating
full implementation of state damage prevention programs. INGAA further
suggested PHMSA actively promote the use of 811 one-call programs.
INGAA noted excavation damage remains the most prevalent cause of
serious incidents and failure to notify is a primary cause of these
incidents. Many pipeline operators supported the INGAA comments.

    2. INGAA, supported by many of its pipeline operator members, noted
it has a policy goal to apply integrity management principles,
voluntarily, to pipelines beyond HCAs. Their goal is to address 90
percent of the population near pipelines by 2020 and 100 percent by
2030 through application of appropriate principles from ASME/ANSI
B31.8S.
    3. AGA supported application of IM principles, but not assessment
requirements, outside HCAs. AGA commented requiring operators to
understand and address risks is a good application of IM principles.
Many pipeline operators supported the AGA comments.
    4. AGA commented the ANPRM incorrectly states that Sec.  192.935
applies only to pipe within HCAs. AGA noted paragraph (d) of that
section applies to low-stress pipe in Class 3 and 4 areas that is not
in HCAs.
    5. California Public Utilities Commission suggested pipelines
installed prior to the promulgation of federal pipeline safety
requirements (so-called ``pre-code'' pipe) be reassessed more
frequently.
    6. Alaska Natural Gas Development Authority commented Alaska's
experience indicates improved pipeline design and construction
requirements are needed to assure pipeline integrity. These would
include stronger pipe, improved requirements for mainline valves
(including spacing and remote operation), and improved corrosion
control. The Authority also commented that design requirements need to
accommodate likely changes in class location, noting that explosive
growth in some Alaska areas has resulted in rapid changes from Class 1
to Class 3.
    7. One private citizen suggested some level of assessment should be
required for all pipelines.
    8. Another private citizen suggested integrity management plans for
densely populated areas (Class 4 and Class 5--a new class suggested by
the commenter encompassing cities with population greater than 100,000)
should be developed in consultation with local emergency responders.
The commenter further suggested these plans should be available at the
FERC environmental impact study stage and should be reviewed with local
authorities.
    9. Another private citizen suggested information should be shared
across pipeline operators, noting this would augment the knowledge of
individual companies and improve safety. Similarly, the commenter
suggested PHMSA require operators to submit a list of preventive and
mitigative measures that have been implemented and reports of their
effectiveness. The commenter noted PHMSA should know this information
but apparently does not, as indicated by questions posed in this ANPRM
(particularly questions B.1 and B.2).
Comments Submitted for Questions in Topic B
    B.1. What practices do gas transmission pipeline operators now use
to make decisions as to whether/which additional preventive and
mitigative measures are to be implemented? Are these decisions guided
by any industry or consensus standards? If so, what are those industry
or consensus standards?
    1. Most industry commenters indicated ASME/ANSI B31.8S is a common
standard used to guide decisions concerning preventive and mitigative
measures. INGAA suggested enhancing this standard would be the best
approach to provide additional guidance for selection and
implementation of these measures. Other commenters also cited the GPTC
Guide as a useful guideline. INGAA listed other standards used by
pipeline operators, including:

 Common Ground Alliance Best Practices
 Pipelines and Informed Planning Alliance Recommended Practices
 API-RP 1162--Public Awareness Programs,
 API-RP 1166--Excavation Monitoring
 NACE SP0169, other associated NACE standards
 Gas Piping Technology Committee guidance materials
 RSTRENG--A Modified Criterion for Evaluating the Remaining
Strength of Corroded Pipe
 INGAA Foundation Guidelines for Evaluation and Mitigation of
Expanded Pipes

    AGA also noted that operators are guided by their own risk
assessments. Many pipeline operators supported the INGAA and AGA
comments.
    2. Northern Natural Gas reported it does not rely on a specific
consensus standard to select preventive and mitigative measures. It
relies, instead, on company subject matter experts guided by
statistical analyses of their risk model.
    3. Paiute and Southwest Gas reported they use an algorithm
combining risk scores, threats, and the value of specific measures.
Company engineers analyze the results of applying this algorithm and
develop preventive and mitigative measure implementation plans.
    4. An anonymous commenter noted many pipeline operators are
implementing actions that could be considered preventive and mitigative
measures but these actions may not be identified as such if they are
implemented as part of operations and maintenance activities and not
specifically included in IM plans.
    5. INGAA suggested PHMSA would benefit by applying ASME/ANSI B31.8S
in its IM enforcement activities.
    B.2. Have any additional preventive and mitigative measures been
voluntarily implemented in response to the requirements of Sec.
192.935? How prevalent are they? Do pipeline operators typically
implement specific measures across all HCAs in their pipeline system,
or do they target measures at individual HCAs? How many miles of HCA
are afforded additional protection by each of the measures that have
been implemented? To what extent do pipeline operators implement
selected measures to protect additional pipeline mileage not in HCAs?
    1. INGAA reported many pipeline operators have implemented
additional preventive and mitigative measures. INGAA does not keep data
on this and did not provide examples. Some pipeline operators submitted
examples in support of the INGAA comments. Preventive and mitigative
measures cited in these examples include:
     Additional reconnaissance (after seismic events, floods,
etc.);
     Concrete mats over pipelines in areas particularly
susceptible to excavation damage;
     Encroachment sensors;
     Remotely operated valves;
     Removal of casings;
     Completion of CIS surveys;
     Clearing of rights-of-way;
     Derating/deactivating of pipelines;
     Relocation of pipelines;
     Increased inspection of river crossings;
     Lowering of shallow pipelines;
     Installation of additional marker posts;
     Revising marking standards for locates;
     Completing depth-of-cover surveys;
     Enhancing right-of-way patrols.
    In addition, one pipeline operator reported augmented
implementation of many requirements of part 192 and implementation of
some requirements (e.g., operator qualification) beyond their specified
bounds.
    2. AGA also reported many additional preventive and mitigative
actions have been implemented but, again, does not keep data on them.
Examples cited by AGA and its operator members included increased use
of indirect inspection tools, increased patrols, and investigation of
apparent instances of encroachment.

    3. GPTC reported data is not collected concerning voluntary
measures.
    4. Texas Pipeline Association and Texas Oil & Gas Association
similarly reported that they do not collect this data, and there was
only limited response to a survey of their operators regarding this
question. The associations reported their understanding that measures
are not generally implemented system-wide.
    5. California Public Utilities Commission reported some CA
operators are stationing personnel at the location of excavations near
transmission pipelines. CAPUC also noted California's one-call law
requires a mandatory field meeting before any excavation near a
transmission pipeline operating above 60 psi.
    6. An anonymous commenter suggested operators avoid implementing
non-required actions for fear they will lead to new requirements.
    7. Industry comments indicated data is not collected concerning the
extent of implementation of voluntary preventive and mitigative
measures. Some measures are implemented in specific HCAs while others
may be implemented more broadly across a pipeline system. The extent
depends largely on the threat being addressed and its prevalence.
    8. Northern Natural Gas reported it has implemented voluntary
measures outside HCA, citing as examples high-visibility markers in
Class 1 areas and use of LIDAR leak detection. Northern reported broad
implementation of voluntary measures is more prevalent than site
specific use.
    9. MidAmerican reported virtually all of its transmission pipeline
mileage is subject to at least one preventive and mitigative measure.
    10. Paiute reported nine measures are applied to all of its 856
miles of transmission pipeline while 13 are applicable to all 27 miles
of HCA.
    11. Similarly, Southwest Gas has implemented nine measures on 841
miles and 13 on all 191 miles of HCA.
    12. AGA reported that approximately 195,000 non-HCA miles have been
assessed, generally through assessing pipe upstream and downstream of
the HCA segment.
    B.3. Are any additional prescriptive requirements needed to improve
selection and implementation decisions? If so, what are they and why?
    1. Industry commenters unanimously agreed no new prescriptive
requirements are needed. INGAA pointed out selection of preventive and
mitigative measures is based on criteria in consensus standards and
operator judgment. INGAA contended this allows appropriate
customization and results in improved safety. AGA agreed, noting
operators are in the best position to decide what is needed for their
pipeline systems. GPTC stated that its Guide is sufficient, and there
has been no demonstrated safety need for additional requirements.
Several pipeline operators suggested conducting assessments and making
repairs provides the most effective safety improvement.
    2. Paiute and Southwest Gas suggested a best practices workshop to
share industry experience could be beneficial.
    3. Accufacts suggested additional prescriptiveness is needed to
guide decisions regarding remote and automatically operated valves in
HCA.
    4. The Alaska Department of Natural Resources would suggest signoff
by a professional engineer on preventive and mitigative action
decisions.
    5. The NTSB recommended improved use of metrics in inspection
protocols, citing their recommendations P-11-18 and 19.
    6. One private citizen suggested the lack of specifically-required
actions in the regulations represents a deficiency in the pipeline
safety regulatory program. The commenter suggested the extent of
operator judgment be limited and that state and local officials should
participate in developing a list of applicable preventive and
mitigative actions.
    7. An anonymous commenter suggested including more examples of
preventive and mitigative actions in the regulations would help guide
operator consideration of appropriate actions. The commenter also
suggested operators be required to update their risk analyses, and
selection of preventive and mitigative actions, more frequently
including after changes in their pipeline systems or the occurrence of
significant events.
    B.4. What measures, if any, should operators be required explicitly
to implement? Should they apply to all HCAs, or is there some
reasonable basis for tailoring explicit mandates to particular HCAs?
Should additional preventative and mitigative measures include any or
all of the following: Additional line markers (line-of-sight); depth of
cover surveys; close interval surveys for cathodic protection (CP)
verification; coating surveys and recoating to help maintain CP current
to pipe; additional right-of-way patrols; shorter ILI run intervals;
additional gas quality monitoring, sampling, and inline inspection tool
runs; and improved standards for marking pipelines for operator
construction and maintenance and one-calls? If so, why?
    1. INGAA, supported by many of its pipeline operator members,
commented prescriptive requirements are not needed. INGAA contended
prescriptive requirements are neither effective nor efficient and that
ASME/ANSI B31.8S and the GPTC Guide provide sufficient guidance.
    2. AGA commented one-call requirements and the actions required by
the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011
are the only actions that should be required on a system-wide basis.
AGA further suggested it could be appropriate to apply the additional
measures required of low-pressure pipelines in Sec.  192.935(d) to
pipelines operating above 30 percent SMYS.
    3. Texas Pipeline Association and Texas Oil & Gas Association
recommended no new requirements be adopted applying specific preventive
and mitigative actions throughout pipeline systems. The associations
noted part 192 already requires application of some measures throughout
pipeline systems and expressed their conclusion these already-specified
measures are sufficient.
    4. MidAmerican commented requiring application of specified
measures throughout pipeline systems would provide a disincentive for
the application of other measures which could be more appropriate.
    5. The NTSB recommended requirements for leak detection in SCADA
systems should be improved, citing their recommendation P-11-10.
    6. California Public Utilities Commission recommended operators be
required to station stand-by personnel at excavations near transmission
pipelines and operator procedures should specify the actions these
stand-by personnel must take. CPUC further suggested these standby
activities should be a covered task under operators' personnel
qualification programs.
    7. Pipeline Safety Trust recommended PHMSA mandate the NTSB
recommendations, noting many are similar to the specific measures
suggested in this question. PST further commented operators should not
be allowed sufficient latitude to render a regulation meaningless.
    8. An anonymous commenter suggested the regulations should not
specify particular preventive and mitigative measures but should
emphasize consideration of potential accident consequences when
selecting actions. The commenter noted there are too many variables to
specify particular actions in regulation.

    9. A private citizen suggested operators should be required to
conduct drills with local responders periodically as part of their
integrity management programs. The commenter noted such drills would
improve coordination and would validate the ability to respond in the
event of an emergency.
    10. A private citizen suggested stronger enforcement is needed
based on the belief that operators should already be taking many of the
actions suggested in this question.
    11. With respect to the specific actions suggested in this
question:
    a. Line-of-sight markers: National Utility Locating Contractors
Association recommended line-of-sight markers be required, noting that
they would reduce the instances of excavators failing to call for a
locate, which the Common Ground Alliance's Damage Information Reporting
Tool (DIRT) continues to indicate is a major cause of excavation
damage. The Association further recommended the message on markers
should be visible from all angles, noting that most current markers are
only visible from two directions. The Commissioners of Wyoming County
Pennsylvania, and MidAmerican suggested line-of-sight markers should be
required, noting that they are a low-cost good practice for improving
safety. An industry consultant disagreed, noting installation would be
impractical in many areas where the sight line is obscured by crops,
terrain, etc.
    b. Depth of cover: MidAmerican opposed required depth of cover
surveys, commenting they are not a good indicator of likely damage and
such surveys are inherently inaccurate. Texas Pipeline Association and
Texas Oil & Gas Association suggested compliance with depth of cover
requirements over time is impractical. They noted operators do not have
full control over rights of way and that owners can make changes. For
example, a landowner may pave an area following grading which reduces
the depth of cover. California Public Utilities Commission recommended
depth of cover surveys be required wherever external corrosion direct
assessment is applied and where vehicles or other loads capable of
damaging the pipeline have access to the surface over the pipeline.
Wyoming County Pennsylvania's Commissioners suggested depth of cover
surveys be required as a good safety practice.
    c. Close interval surveys: MidAmerican recommended against
requiring these surveys. The company noted they are only one means of
determining the adequacy of cathodic protection. The Commissioners of
Wyoming County Pennsylvania recommended such surveys be required as a
good safety practice.
    d. Coating surveys and re-coating: MidAmerican opposed a
requirement for coating surveys, noting holidays are found and repaired
through in-line inspection and external direct assessment. The company
further noted pipe replacement is often a superior repair to recoating.
The Wyoming County Commissioner commented periodic coating surveys are
a good practice and recommended that they be required.
    e. Additional right of way patrols: MidAmerican and the Wyoming
County Commissioners agreed increased frequency of patrols would be
appropriate. MidAmerican noted patrols are a relatively low cost action
that generates useful data.
    f. Shorter ILI intervals: MidAmerican opposed shorter intervals,
noting many lines cannot accommodate in-line inspection or more
frequent runs. The Wyoming County Commissioners argued that frequent
assessment is a good practice that should be required.
    g. Additional gas quality monitoring: MidAmerican opposed such a
requirement, arguing it would be redundant for distribution pipeline
operators receiving gas from suppliers. The Wyoming County
Commissioners argued frequent gas monitoring would be a good practice.
    h. Improved pipeline marking standards: MidAmerican agreed
implementing new marking standards would be a low cost action. Wyoming
County again noted this is a good practice.
    B.5. Should requirements for additional preventive and mitigative
measures be established for pipeline segments not in HCAs? Should these
requirements be the same as those for HCAs or should they be different?
Should they apply to all pipeline segments not in HCAs or only to some?
If not all, how should the pipeline segments to which new requirements
apply be delineated?
    1. INGAA, supported by many of its member companies, argued
preventive and mitigative measures should be applied to non-HCA areas
on a risk basis rather than by prescriptive requirement. INGAA
commented this is a more effective and efficient means of increasing
pipeline safety.
    2. AGA commented codifying different requirements for non-HCA areas
would likely cause confusion and extending existing IM requirements to
non-HCA areas would create an enormous burden for PHMSA and states. AGA
noted the NTSB has already questioned the ability of regulators to
apply the existing IM inspection protocols to HCA mileage. AGA
recommended one-call and the actions required by statute be the only
additional measures required system-wide.
    3. GPTC, Texas Pipeline Association, Texas Oil & Gas Association,
and two pipeline operators opposed requirements for preventive and
mitigative actions in non-HCA areas. These commenters argued it is
important to allow pipeline operators the flexibility to select actions
that are appropriate to their circumstances and implementing actions
required arbitrarily would be expensive and ineffective.
    4. Northern Natural Gas suggested PHMSA expand the HCA definition
gradually over time rather than imposing IM requirements outside HCA.
Northern commented such an approach would retain and expand the focus
on areas posing the highest risk.
    5. MidAmerican opposed additional requirements for preventive and
mitigative actions, noting all pipeline is covered by other
requirements in part 192 and it is better to focus enhanced
requirements on areas posing highest risk.
    6. AGA commented measures required in HCA should always be equal to
or more stringent than measures required outside of HCA. AGA noted this
is a fundamental principle of integrity management: Focusing on areas
posing higher risks.
    7. Ameren Illinois and an anonymous commenter suggested better
enforcement and/or specificity for provisions requiring operators
consider other areas of their systems when problems are discovered
would be more effective than requiring preventive and mitigative
measures outside HCA.
    8. ITT Exelis Geospatial Systems commented requirements should be
the same in- or outside HCA. They contended non-HCA areas are not
monitored for leakage as often as Class 3 and 4 locations. They
suggested their LIDAR system would allow effective and efficient leak
surveys in all locations.
    9. A public citizen recommended exposed pipe be wrapped in bright
colors and protected from damage whether inside or outside of HCA. The
commenter suggested analysis of data from CGA's Damage Information
Reporting Tool would be an effective preventive measure.
    B.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, among other factors, the potential costs of
modifying the existing regulatory requirements pursuant to the
commenter's suggestions.
    1. Northern Natural Gas reported the additional cost of
preventative and mitigative measures it employs, including instrumented
aerial leakage surveys, close-interval surveys, additional mailings and
additional signage, has been approximately $950,000. Northern further
reported the approximate cost of conducting assessments through in-line
inspection or pressure testing for all high-consequence areas every
seven years is $45,000,000 and reduction of the inspection interval
would increase the cost accordingly.
Response to Topic B comments
    Section 5 of the Act requires that the Secretary of Transportation
complete an evaluation and issue a report on whether integrity
management requirements should be expanded beyond HCAs and whether such
expansion would mitigate the need for class location requirements.
Aspects of this topic that relate to applying a risk analysis to
determine additional preventive and mitigative measures for non-HCA
pipeline segments will be addressed later, pending completion of the
evaluation and report. PHMSA will review the comments received on this
topic and will address them in the future in light of these statutory
requirements.
    Section 3 of the Act requires that the Secretary of Transportation
complete an evaluation and issue a report on the impact of excavation
damage on pipeline safety. Aspects of this topic that relate to
additional preventive and mitigative measures for damage prevention
will be addressed after completion of the evaluation and report. PHMSA
will review the comments received on this topic and will address them
in the future in light of this evaluation and report.
    Section 6 of the Act requires that the Secretary of Transportation
provide guidance on public awareness and emergency response plans.
Aspects of this topic that relate to additional preventive and
mitigative measures for public awareness and emergency response will be
further evaluated in conjunction with this statutory mandate. PHMSA
will review the comments received on this topic and will address them
in the future in light of this evaluation.
    Two specific areas of preventive and mitigative actions addressed
in the IM requirements (49 CFR 192.935) are leak detection and
automatic/remote control valves. The IM rule does not require specific
measures be taken to address these aspects of pipeline design and
operations, but does include them among candidate preventive and
mitigative measures operators should consider. Both of these topics are
the subject of recommendations that the NTSB made (recommendations P-
11-10 and P-11-11) following the San Bruno explosion. In response to
these recommendations, PHMSA conducted a public workshop on March 27,
2012, to seek stakeholder input on these issues, and is sponsoring
additional research and development to further inform PHMSA's response
on these issues. Aspects of this topic that relate to leak detection
and automatic/remote control valves will be addressed after completion
and evaluation of the above activities. PHMSA will review the comments
received on leak detection and automatic/remote control valves and will
address them in the future in light of this evaluation.
    PHMSA is proposing to add requirements for enhanced preventive and
mitigative measures to address internal and external corrosion control.
The intent of the IM rulemaking is to enhance protections for high
consequence areas. PHMSA believes that enhanced requirements for
internal corrosion and external corrosion control are prudent. To
address internal corrosion, PHMSA is proposing specific requirements
for operators to monitor gas quality and contaminants and to take
actions to mitigate adverse conditions. To address external corrosion,
PHMSA is proposing specific requirements for operators to monitor and
confirm the effectiveness of external corrosion control through
electrical interference surveys and indirect assessments, including
cathodic protection surveys and coating surveys, to take actions needed
to mitigate conditions that are unfavorable to effective cathodic
protection, and to integrate the results of these surveys with
integrity assessment and other integrity-related data. PHMSA addresses
this topic in more detail in response to comments related to Topic I,
Corrosion Control.

    Note: Specific comments submitted for Topic B that are related
to risk and integrity assessments are addressed under Topics E and
G.

C. Modifying Repair Criteria

    The existing integrity management regulations establish criteria
for the timely repair of injurious anomalies and defects discovered in
the pipe (49 CFR 192.933). These criteria apply to pipeline segments in
an HCA, but not to segments outside an HCA. The ANPRM announced that
PHMSA is considering amending the integrity management rule by revising
the repair criteria to provide greater assurance that injurious
anomalies and defects are repaired before the defect can grow to a size
that leads to a leak or rupture. In addition, PHMSA is considering
establishing repair criteria for pipeline segments located in areas
that are not in an HCA in order to provide greater assurance that
defects on non-HCA pipeline segments are repaired in a timely manner.
The following are general comments received related to the topic and
then comments related to the specific questions:
General Comments for Topic C
    1. INGAA reported its members' commitment to apply ASME/ANSI B31.8S
corrosion anomaly criteria both inside and outside of HCAs. INGAA noted
that new research to refine and extend the technical bases for
responding to corrosion anomalies identified primarily by ILI has been
completed by Pipeline Research Council International, whose report was
expected to be published in the first quarter of 2012. INGAA also
reported a commitment to develop and use criteria for mitigation of
dents, corrosion pitting, expanded pipe corrosion, and selective seam
weld corrosion. Numerous pipeline operators supported INGAA's comments.
    2. AGA suggested that ASME/ANSI B31.8S should be the basis for
defining anomalies requiring remediation. Anomalies not meeting the
criteria in that standard, in AGA's opinion, do not require repair. AGA
further commented that risk prioritization of maintenance and anomaly
response should not be regulated because operators are in the best
position to know the factors influencing prioritization for apparently-
similar anomalies. AGA also suggested that PHMSA review INGAA's paper
``Anomaly Response and Mitigation Outside of High Consequence Areas
when Using in Line Inspection,'' dated May 30, 2010, as this paper
forms the basis for current industry response outside of HCAs. Numerous
pipeline operators supported AGA's comments.
    3. Accufacts contended that there have been too many corrosion-
caused ruptures occurring shortly after in-line

inspection runs and that this indicates the need for more prescriptive
criteria for corrosion evaluation and remediation.
    4. Alaska Department of Natural Resources commented that repairs
should be made using permanent methods, and that clamps and similar
repairs are not sufficient.
Response to General Comments for Topic C
    PHMSA appreciates the information provided by the commenters.
Because the current repair criteria only address corrosion metal loss
as an immediate condition, PHMSA agrees that more prescriptive repair
criteria are needed to address significant corrosion metal loss that
does not meet the immediate repair criterion, similar to the hazardous
liquid integrity management repair criteria at 49 CFR 195.452(h). In
addition, other conditions that are not currently addressed in the
repair criteria, such as stress corrosion cracking and selective seam
weld corrosion, are addressed in ASME B31.8S and other sources, but not
explicitly addressed in part 192. PHMSA is proposing to enhance the
repair criteria for HCA segments and is also proposing to add specific
repair criteria for pipeline in non-HCA segments. In general, PHMSA is
proposing to add more immediate repair conditions and more one-year
conditions for HCA segments. The additional criteria address conditions
not previously addressed, such as stress corrosion cracking, and also
include more specific one-year criteria for corrosion metal loss, based
on the design factor for the class location in which the pipeline is
located, to address corrosion metal loss that reduces the design safety
factor of the pipe. PHMSA is also proposing to apply similar repair
criteria in non-HCA segments, except that response times will be
tiered, with longer response times for non-immediate conditions. PHMSA
reviewed available industry literature, including ASME/ANSI B31.8S, in
developing the proposed repair criteria. Specific aspects of the
proposed rules are discussed in response to the specific questions for
Topic C, below.
    PHMSA has not addressed the specific procedures and techniques for
performing repairs in this rulemaking, but may do so at a later date.
Comments Submitted for Questions in Topic C
    C.1. Should the immediate repair criterion of failure pressure
ratio (FPR) <=1.1 be revised to require repair at a higher threshold
(i.e., additional safety margin to failure)? Should repair safety
margins be the same as new construction standards? Should class
location changes, where the class location has changed from Class 1 to
2, 2 to 3, or 3 to 4 without pipe replacement have repair criteria that
are more stringent than other locations? Should there be a metal loss
repair criterion that requires immediate or a specified time to repair
regardless of its location (HCA and non-HCA)?
    1. INGAA, supported by numerous pipeline operators, commented the
FPR criterion need not be changed, noting there have been no reported
incidents due to the criterion being too lax. INGAA also objected to
PHMSA's characterization of this issue, noting that repair criteria
already exceed 1.1 FPR; the 1.1 FPR criterion in the regulations
governs response to anomalies and not the criteria to which repairs
must be made.
    2. AGA, supported by numerous of its pipeline operator members,
commented that the FPR criterion should not be changed. AGA contended
that the criterion already provides a 10 percent safety margin and is
based on sound engineering practices.
    3. Northern Natural Gas and Kern River stated that conservatism is
present in burst pressure calculations and in the measurement of
anomalies (considering tool tolerance), providing a safety margin
greater than 10 percent.
    4. Accufacts argued against changing the FPR criterion, but
suggested that PHMSA require operators to use better assumptions in
their failure analyses. Accufacts suggested that the regulations should
focus on preventing failures but that existing safety margins need not
be increased.
    5. Texas Pipeline Association, Texas Oil & Gas Association, Atmos,
and MidAmerican opposed changes to this criterion. These commenters
noted that experience through the baseline inspections has demonstrated
the criterion is adequate and ASME/ANSI B31.8S remains a good guide for
anomaly response. Atmos added that this criterion separates immediate
repairs from scheduled repairs: It allows a risk-based focus on more
serious anomalies but does not mean that anomalies providing more than
10 percent margin to burst pressure are never addressed.
    6. California Public Utilities Commission suggested that the FPR
criterion be increased to 1.25 times MAOP. CPUC noted that the 10
percent margin in the current criterion can be completely erased by the
10 percent margin to safety relief settings allowed by Sec.  192.201.
    7. INGAA commented that additional repair criteria are not needed.
INGAA noted that Sec. Sec.  192.485(a) and 192.713(a) already specify
repair criteria applicable to pipe outside HCA. Numerous pipeline
operators supported INGAA's comments.
    8. AGA, supported by numerous of its pipeline operator members,
suggested that safety margins for repairs need not be the same as those
for new construction. AGA argued that the construction margins are
intended to address potential unknowns and forces applied during
construction, which are not applicable to repairs.
    9. Accufacts, Northern Natural Gas, and an anonymous commenter
agreed that repairs, once initiated, should meet new construction
safety margins.
    10. INGAA and several of its pipeline operator members argued that
repair criteria should not be more stringent where class location has
changed. INGAA noted that Sec.  192.611 does not change the original
design criteria for segments that have been subject to a change in
class location and there is no incident experience suggesting that
additional safety margin is needed in these cases.
    11. Northern Natural Gas and Kern River argued against a change in
repair criteria where class location has changed, noting that the
likelihood of failure of an anomaly is not affected by the class
location and that treatment in accordance with integrity management
requirements already considers risk.
    12. MidAmerican, Paiute, and Southwest Gas added that use of the
factor failure pressure divided by MAOP in ASME/ANSI B31.8S already
reflects any change in MAOP necessitated by a change in class location.
    13. Accufacts commented that repair criteria should be commensurate
with the more restrictive design criteria of higher class locations.
    14. INGAA commented no new metal loss criterion is needed, noting
that its members use HCA response criteria as a guide for responding to
indications of metal loss outside of HCAs. Numerous pipeline operators
supported INGAA's comments.
    15. AGA commented any metal loss criterion should reflect current
science and should be the same regardless of class location. AGA
suggested that immediate response to any indication of a dent with
metal loss is not needed, noting that there have been many examples of
dents with metal loss not sufficient to require recalculating remaining
strength. AGA also noted the external corrosion direct assessment
standard requires a similar response regardless of whether an
indication is in

or outside HCA. Numerous pipeline operators supported AGA's comments.
    16. Accufacts encouraged PHMSA to establish a prompt-action
criterion for wall loss inside or outside HCAs, suggesting the focus
should be on preventing ruptures regardless of where they occur.
Accufacts also cautioned PHMSA against accepting studies attempting to
show that 80 percent wall loss is sometimes acceptable, and stated that
continued operation with such wall loss is too risky for onshore
pipelines.
Response to Question C.1 Comments
    PHMSA appreciates the information provided by the commenters. The
majority of comments supported no changes to the immediate repair
criterion of predicted failure pressure of less than or equal to 1.1
times MAOP for HCAs, and PHMSA is not proposing to change this
criterion; however, PHMSA is proposing several changes to enhance the
repair criteria both for HCA segments and non-HCA segments. For
immediate conditions, PHMSA proposes to add the following to the
immediate repair criteria: Metal loss greater than 80% of nominal wall
thickness, indication of metal-loss affecting certain types of
longitudinal seams, significant stress corrosion cracking, and
selective seam weld corrosion. These additional repair criteria would
address specific issues or gaps with the existing criteria. The methods
specified in the IM rule to calculate predicted failure pressure are
explicitly not valid if metal loss exceeds 80% of wall thickness.
Corrosion affecting a longitudinal seam, especially associated with
seam types that are known to be susceptible to latent manufacturing
defects such as the failed pipe at San Bruno, and selective seam weld
corrosion are known near-term integrity threats. Stress corrosion
cracking is listed in ASME B31.8S as an immediate repair condition,
which is not reflected in the current IM regulations. PHMSA proposes to
add requirements to address these gaps.
    The current regulations include no explicit metal loss repair
criteria, other than one immediate condition. The regulations direct
operators to use Figure 4 in ASME B31.8S to determine non-immediate
metal loss repair criteria. PHMSA now proposes to explicitly include
selected metal loss repair conditions in the one-year criteria. These
proposed criteria are consistent with similar criteria currently
invoked in the hazardous liquid integrity management rule at 40 CFR
195.452(h). In addition, PHMSA proposes to incorporate safety factors
commensurate with the class location in which the pipeline is located,
to include predicted failure pressure less than or equal to 1.25 times
MAOP for Class 1 locations, 1.39 times MAOP for Class 2 locations, 1.67
times MAOP for Class 3 locations, and 2.00 times MAOP for Class 4
locations in HCAs. Lastly, in response to the lessons learned from the
Marshall, Michigan, rupture, PHMSA proposes to include any crack or
crack-like defect that does not meet the proposed immediate criteria as
a one year condition. PHMSA proposes to apply these same criteria as
two-year conditions for non-HCAs.
    PHMSA agrees with Accufacts' comment that the regulations should
focus on preventing failures but that existing safety margins are
adequate when properly applied. Therefore, the proposed rule does not
propose to increase safety margins such as the design factor. PHMSA
maintains that the proposed changes discussed above provide a tiered,
risk-based approach to metal loss repair criteria and by requiring
predicted failure pressures as a function of class locations does not
compound safety margins. Counter to INGAA's and AGA's comments that
repair criteria should not be more stringent where class location has
changed, PHMSA believes the tiered approach to metal loss repair
criteria, which is a function of class location, provides a logical
framework to address the risk presented by these types of pipeline
anomalies.
    In conjunction with enhanced repair criteria, PHMSA is proposing
specific new regulations to require that operators properly analyze
uncertainties and other factors that could lead to non-conservative
predictions of failure pressure, and time remaining to failure, when
evaluating ILI anomaly indications. PHMSA specifically is proposing
that operators must analyze specific known sources of uncertainty
regarding ILI tool performance, anomaly interactions, and other sources