# Gas Transmission Integrity Management FAQs

- **operation:** document
- **citation:** PHMSA Guidance, Gas Transmission Integrity Management FAQs
- **title:** Gas Transmission Integrity Management FAQs
- **source type:** guidance
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** guidance
- **official:** true
- **published on:** 2021-01-15
- **effective on:** 2021-01-15
- **summary:** Gas Transmission Integrity Management FAQs Document Final GAS IM FAQs 8-26-21.pdf (653.41 KB) This site provides information about PHMSA's implementation of Control Room Management oversight, and links to other educational information on human factors and human operational performance. Issued Date: Friday, January 15, 2021
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- **app url:** https://regulus.evalyn.ai/document/phmsa-guidance-gas-transmission-integrity-management-faqs-a3046830
- **source url:** https://www.phmsa.dot.gov/pipeline/gas-transmission-integrity-management/gas-transmission-integrity-management-faqs
**body:**

Gas Transmission Integrity Management FAQs

Document

 Final GAS IM FAQs 8-26-21.pdf (653.41 KB)

        This site provides information about PHMSA's implementation of Control Room Management oversight, and links to other educational information on human factors and human operational performance.

          Issued Date: Friday, January 15, 2021

<<<PAGE 1>>>

Gas Transmission Integrity Management: FAQs
The Pipeline and Hazardous Materials Safety Administration (PHMSA) provides written clarification of the
pipeline safety regulations (49 CFR Parts 190-199) in the form of frequently asked questions (FAQs) and
other guidance materials. The FAQs contained on this page are intended to clarify, explain, and promote
better understanding of the gas transmission pipeline integrity management (IM) regulations. These FAQs
reflect PHMSA’s current application of the regulations to the specific implementation scenarios presented.
FAQs are not substantive rules, themselves, and do not create legally enforceable rights, assign duties, or
impose new obligations not otherwise contained in the existing regulations and standards, but are provided to
help the regulated community understand how to comply with the regulations. However, an operator who is
able to demonstrate compliance with the FAQs is likely to be able to demonstrate compliance with the
relevant regulations. If a different course of action is taken by a pipeline operator, the operator must be able
to demonstrate that their conduct is in accordance with the regulations. Written regulatory interpretations
regarding specific situations may also be obtained from PHMSA in accordance with 49 CFR Part 190, §
190.11.
The rule does not apply to gathering lines. Section 192.9 has been changed to make this clear. The rule
does apply to low-stress pipeline that meets the definition in 192.3 as a transmission line, but some
requirements are slightly different for low-pressure transmission pipelines (i.e. <30% SMYS).
FAQ Topical Categories
• General (6)
• Rule Basics (2)
• Rule Applicability (6)
• Time Periods (6)
• Integrity Management Programs (9)
• HCA Identification (38)
• Threat/Risk Analysis (7)
• Identification of Threats (1)
• Data Integration (4)
• Risk Analysis and Prioritization (6)
• Specific Threats (2)
• Assessment (15)
• Baseline Assessment Plan (BAP) (3)
• Assessment Methods (28)
• Continual Assessment and Evaluation (11)
• Remediation (16)
• Preventive and Mitigative Measures (5)
• Performance Measures (5)
• Record Keeping (3)
• Management of Change (MOC) (1)
• Regulatory and External Interaction (2)
• Communication Plan (1)
• Notification (7)
• Inspection (3)
• Enforcement (3)
• State Agencies and Intrastate Pipelines (2)
• Exceptional Performance Deviations (2)
• ECDA for Cased Pipe (30)

<<<PAGE 2>>>

General FAQ
FAQ-10. If a pipeline subject to 192 Subpart O is sold, does the new operator "inherit" integrity
management plans and deadlines from the original operator? [05/18/2004]
The regulatory deadlines for assessments (e.g., that re-assessments be conducted within specified intervals,
based on operating stress levels) continue to apply, as well as the schedule requirements for any remediation
required by 192.933 that may be pending at the time ownership of the pipeline is transferred. Compliance
deadlines established in 192 Subpart O for identifying segments in HCAs and for completing 50% or 100% of
Baseline Assessments continue to apply. For purposes of integrity management, an operator acquiring a
pipeline would be expected to integrate that pipeline into its integrity management program. OPS would
expect this integration to occur within one year. Integration of new assets into existing Baseline Assessment
Plans may result in realigning schedules for future assessments based on the relative risk of the acquired
pipeline and the operator’s existing pipeline(s).
Integration of acquired pipe into an operator's IM plan could constitute the kind of substantial change in the
IM program for which notification is required under 192.909(b), if the integration caused significant changes
to existing schedules and programs.
FAQ-11. Who will be held accountable for implementing Integrity Management requirements in a
case where an operator transfers pipeline assets to another company but retains responsibility,
by contract, for maintenance and integrity management activities until some later
date? [06/29/2004]
Typically, OPS inspects the operator for compliance with the pipeline safety regulations, however,
compliance responsibility would have to be determined on a case by case basis and is contingent on the
terms of contracts, operating agreements, and any other relevant correspondence between the involved
parties. Depending on the terms of the agreement, either or both could be held responsible.
FAQ-12. If a pipeline transports both gas and liquids (e.g., some off shore lines), does the
hazardous liquid integrity management rule or the gas integrity management rule
apply? [02/20/2004]
Lines that transport both liquids and gas must meet requirements applicable to both. In practice, this means
that the more stringent requirements must be met.
FAQ-155. In several places, the rule requires that operators follow Appendices in ASME/ANSI
B31.8S. The title of both Appendices A and B in the standard indicate they are non-mandatory.
Must the requirements in these Appendices be followed verbatim? [05/05/2004]
Where sections of consensus standards are incorporated by reference into a rule, those sections become
binding requirements the same as if the language were repeated in the rule. Operators must follow the
requirements in the Appendices of ASME/ANSI B31.8S when those Appendices, or sections thereof, are
referenced in the rule, even though the standard indicates that the appendices are non-mandatory.
FAQ-159. What constitutes an "incident" of the kind for which operators implementing
performance-based programs must evaluate for implications to their pipelines and IM programs
(192.913(b)(1)(v)? [03/09/2005]
Incidents are as defined for incident reporting in 49 CFR 191.3. OPS expects, however, that operators
deviating from the requirements of prescriptive programs on the basis of "exceptional performance" under
192.913(b) will evaluate events that involve unintentional release of gas but which do not reach the reporting
threshold. Such events can illuminate lessons that, if acted upon, can avoid additional events, some of which
may produce greater consequences. OPS expects that operators with mature programs (i.e., those
demonstrating "exceptional performance") will seek to acquire and act on these lessons, and that their
evaluations of such events will have a degree of transparency that allows OPS to also learn from the
evaluations
FAQ-161. Can prior assessments be relied upon to meet the requirement that operators begin
assessment activities by June 17, 2004? [05/26/2004]
Yes, provided the assessment meets the requirement of Subpart O and can be used as a baseline
assessment.

<<<PAGE 3>>>

[Top]
Rule Basics FAQ
FAQ-167. How should the operator address "must" and "shall" statements in the standard? In
some cases, the standard provides for an alternative action if the "must" and "shall" statements
are not implemented. [06/29/2004]
When standards are incorporated into a rule by reference, the requirements of the standard become
requirements of the rule. Operators are required to implement "must" and "shall" statements in the standard.
Where the standard provides an alternative, e.g., in the event an action that "must" be done cannot be
accomplished, the alternative must be implemented with appropriate justification. (In the event of conflicts
between provisions in the standard and the Rule, the Rule takes precedence).
FAQ-244. What is the OPS position with regard to implementation of "should" statements in
industry standards that are invoked by the rule? [01/11/2006]
OPS expects operators to implement "should" statements in industry standards that are invoked by the rule.
Operators may choose to implement an alternative approach in meeting the recommendations of invoked
standards. If this approach is taken, program requirements for the alternative approach must exist in IM
Program documents and records must be generated by the alternative approach. The IM Program documents
must also technically justify that the alternative approach provides an equivalent level of protection. If an
operator chooses not to implement a "should" statement in an invoked standard, a sound technical basis for
why it has not been implemented must be documented in the IM Program documents.
[Top]
Rule Applicability FAQ
FAQ-7. Do the requirements of the rule apply to "idle" pipe? [02/20/2004]
The regulations do not define "idle" pipe. Pipe is considered either active or abandoned. OPS understands
"idle" pipe, as used in the context of this question, as pipe not currently being used to move gas but that
could be put back in service at a future date. All pipe is subject to the requirements of the integrity
management rule. However, idle pipe presents different risks and different treatment is appropriate.
In-service pipe (i.e., that contains gas, but is not presently being used to transport gas) represents a
potential hazard to public health and the environment, even though idle. If such pipe leaks or ruptures, an
explosion could result. Leaks may go undetected for some time, since idle pipe may not be covered by
operator's SCADA systems. For these reasons, operators must meet all requirements and deadlines for pipe
that contains gas. Such pipe must be included when determining if the requirement to assess 50% of
covered pipeline mileage by December 17, 2007, has been met.
Out-of-service pipe (i.e., pipe laid up with nitrogen) represents much less hazard. Degradation of such pipe
can occur, but is not likely to result in safety impacts. OPS will accept deferral of activities required by the
rule for out-of-service pipe. All deferred activities must be completed as part of any later return of that line
to service. A baseline assessment need not be run immediately if the deadline for completing baseline
assessments (i.e., December 17, 2012) has not yet expired, unless the risk posed by the line would require
an earlier assessment. The baseline assessment plan should be modified to assure that a baseline
assessment is completed by the appropriate deadline. If the deadline has expired, then a baseline
assessment must be completed as part of returning the line to service.
Adding an idle line into the IM program would be considered a substantive program change and would
require notification under 192.909(b).
FAQ-84. The Integrity Management Program portion of the rule [192.907] applies to all portions
of a pipeline system that are in HCAs, including compressor stations, metering stations, and
other equipment. What must an operator do to comply with the rule for these
facilities? [03/04/2005]
The integrity assessment provisions of the rule apply only to line pipe, including pipe that may be within the
boundaries of facilities (e.g., compressor stations, metering stations). The other provisions of the rule apply

<<<PAGE 4>>>

to the equipment in these facilities (e.g., compressors) if the locations meet the criteria to be designated
HCAs. Thus, operators must consider facilities when establishing potential impact circles (the diameter of the
pipe into/out of the equipment should be used), and should include in their integrity management program
processes for addressing these facilities. These processes should integrate all available information affecting
the likelihood and the consequences of equipment or facility failure and identify and implement additional
preventive or mitigative measures to reduce risk at these facilities, if needed. An operator's performance
monitoring process should evaluate the effectiveness of these processes and the risk controls that are
implemented to reduce facility risk.
FAQ-150. What requirements must an operator meet if there are no high consequence areas on
any of its transmission pipelines. [06/20/2005]
An operator need not develop an integrity management program if there are no high consequence areas on
its system. The operator must have completed an evaluation to determine that no high consequence areas
exist, and this evaluation must be maintained available for inspection. Even if no HCAs exist, however, there
are some requirements in Subpart O with which an operator must comply:
- An operator must have a process to periodically evaluate its pipeline to determine if new HCAs have been
created. Changes along the pipeline route, including housing construction and creation of new facilities
meeting criteria in the definition of identified sites could cause HCAs to come into existence. An operator
must be able to demonstrate that it has periodically evaluated its pipeline to assure that there continue to
be no HCAs.
- For transmission pipelines operating below 30 percent of SMYS in class 3 or 4 locations but not in an HCA,
enhanced protection against third-party damage must be implemented in accordance with 192.935(d).
- An operator must submit semi-annual "performance measure" reports in accordance with 192.945(a)
indicating that there are no HCAs on its system.
If the periodic evaluation identifies that a new HCA exists, then the operator must prepare an integrity
management plan and meet all the requirements of subpart O.
FAQ-188. Are jurisdictional gathering lines covered? [06/09/2004]
No. See 192.9.
FAQ-190. How do LDC operators and/or regulators define "distribution center"? (necessary to
determine amount of transmission line.) [06/29/2004]
"Distribution center" is not defined in federal pipeline safety regulations. State definitions can vary. OPS
recognizes the actions of each state in defining what constitutes a distribution center.
FAQ-247. For plastic transmission pipeline, must I meet all of the requirements in the sections
specified in Section 192.901 or just those requirements specifically directed at plastic
pipe? [08/31/2009]
Section 192.901 states that of the requirements in subpart O only the requirements in Sections 192.917,
192.921, 192.935 and 192.937 apply to plastic transmission pipeline. Each of these sections contains
requirements specifically applicable to plastic pipelines. Operators of plastic transmission pipelines must
meet the requirements in these sections that are specifically directed at plastic pipelines and need not
comply with other requirements in the designated sections.
[Top]
Time Periods FAQ
FAQ-124. The rule includes many requirements that do not have specified time periods for
completion. Examples include gathering and integrating data and information on the entire
pipeline, updating risk assessments when the results of assessments are available and
identifying HCAs for new pipe. How soon must these actions be completed? [03/09/2005]
OPS expects operators to diligently pursue completion of actions required by the rule. At the same time, OPS
recognizes that these actions cannot occur immediately. OPS inspectors will assess an operator's plans,
actions, and progress to verify that an operator is making a good faith effort to comply.

<<<PAGE 5>>>

For immediate repairs, physical remediation may take some time, but should be done promptly. Immediate
action is needed, however, to assure safety. OPS expects that actions to reduce pressure or shut in the line
will begin as soon as a defect meeting immediate repair criteria is identified.
For the specific example of identifying HCAs for newly-installed pipe, the requirements for newly-identified
HCAs apply. Any HCAs on the new pipe must be identified and included in the baseline assessment plan
within one year (192.905(c)). These new HCAs must be assessed within ten years from date of installation
of the new pipe (192.921(g)).
FAQ-179. How long does an operator that has had no HCAs, and therefore no integrity
management program, have to develop an integrity management program after it discovers a
new HCA? [08/19/2004]
Section 192.905(c) requires that newly-identified HCAs be incorporated into an operator’s baseline
assessment plan within one year from the date the area is identified. This requirement applies to operators
who previously had no HCAs and thus no IM program. They must develop a program, which includes a
baseline assessment plan, within one year to address the new areas (and any that may be identified later).
FAQ-196. Is there any time limit between step 2 and step 3 in the ECDA process (indirect exam
and direct exam)? [01/14/2005]; [Revised 01/15/2021]
The provisions of NACE RP0502-2010, which is incorporated into the rule by reference, govern the use of
ECDA. The recommended practice does not specify any time limit between step 2, Indirect Inspection, and
step 3, Direct Examination. OPS expects that operators would perform direct examinations shortly after
completing the indirect inspection step, particularly if any severe indications are identified. Operators must
be prepared to justify that any delay between these two steps does not affect the continued validity of the
indirect inspection results or represent an imminent threat to pipeline integrity. Also, refer to FAQ-232.
FAQ-237. When must the baseline assessment be completed for piping installed after the
effective date of the rule? [12/12/2006]
Any newly-constructed gas transmission pipeline placed into service after the effective date of the integrity
management rule, February 14, 2004, is considered "newly-installed" for purposes of the rule. Therefore,
the baseline assessment on such piping is not due until 10 years following the installation of the pipeline.
The same applies to pipe in covered segments that operators replace. In this case, the operator may credit
this mileage as "assessed" for determining compliance with the 50% progress milestone. The ten-year due
date for conducting the baseline assessment for new pipe would also apply to pipe replaced under this
circumstance. This does not, however, relieve the operator of requirements to conduct tests required under
other provisions of Part 192 associated with placing pipeline into service.
FAQ–281. How do I extend the assessment schedule beyond 7 years? [02/11/2019]
Notify PHMSA, in accordance with 49 CFR 192.949, of the need for an extension, which may not exceed 6
months. The notification must be made 180 days prior to end of the calendar 7-year assessment deadline
and include sufficient information to justify the extension. If unexpected conditions (such as weather-related
conditions, assessment tool malfunctions, changes in field or operating conditions, or local gas supply issues)
make the 180-day notification impracticable, the operator must make the notification as soon as practicable
and justify why shorter notice was necessary.
FAQ–282. What constitutes sufficient information to justify extension of the assessment interval?
[02/11/2019]
Documentation is required to comply with 49 CFR 192.947 and must include: An explanation as to why the
deadline could not be met and how it will not compromise safety, and identification of any additional actions
necessary to ensure public safety during the extension time period.
[Top]
Integrity Management Programs FAQ
FAQ-72. When must the Baseline Assessment Plan and Framework be completed?[05/20/2004]
The Baseline Assessment Plan and the Framework both must be prepared by December 17, 2004.
FAQ-73. Will OPS prepare templates for Baseline Assessment Plans or Integrity Management
Program Frameworks that operators can use? [05/20/2004]
No. Because of the significant diversity in operator integrity management programs and processes, OPS does

<<<PAGE 6>>>

not believe it is possible to develop a useful template that is broadly applicable across the industry. As long as
the basic requirements for these documents as specified in 49 CFR 192, Subpart O, are clearly and
completely addressed, an operator is free to use a format for these documents that best supports its internal
management and operational needs.
FAQ-74. What is the difference between an acceptable Integrity Management Framework and a
fully developed Integrity Management Program? [05/18/2004]
The integrity management rule requires operators to develop and implement an Integrity Management
Program. The Integrity Management Program Framework lays the foundation for how the operator intends
to develop and implement its program. As described in 192.911, the elements of an integrity management
program must include several management, analytical, and operational processes. OPS expects that a

<<<PAGE 7>>>

number of operators may not have fully developed these aspects of their integrity management programs at
this time. OPS also recognizes that making significant, fundamental changes in operator management,
analytical, and operational processes and implementing new analytical tools takes time. As such, OPS does
not expect operators to have fully mature integrity management programs by the initial deadline (December
17, 2004).
As described in 192.907, OPS expects the integrity management framework to describe how an operator
currently addresses each element of an integrity management program, and their plans for how they intend
to improve these processes to reach a fully-developed integrity management program. (OPS expects that an
operator will have an established process or procedure for any activities that are being implemented).
Hence, the framework is a roadmap for developing a full integrity management program, and should include
timeframes for completing intended improvements. A fully developed integrity management program would
include complete, well-documented, and effectively implemented processes for all integrity management
program elements defined in 192.911. During OPS inspections, each operator's performance in implementing
its framework will be examined.
FAQ-76. What is an Integrity Management Program? [05/20/2004]
An Integrity Management Program begins with a written framework describing how the elements which
follow will be implemented. Elements required to be part of the program (and the paragraphs of the rule in
which they are described) are:
• An identification of all high consequence areas (192.905).
• A baseline assessment plan (192.919 and 192.921).
• An identification of threats to each covered pipeline segment, which must include data integration and a risk
assessment. An operator must use the threat identification and risk assessment to prioritize covered segments for
assessment (192.917) and to evaluate the merits of additional preventive and mitigative measures (192.935) for
each covered segment.
• A direct assessment plan, if applicable (192.923, and depending on the threat assessed, 192.925, 192.927, or
192.929).
• Provisions for remediating conditions found during an integrity assessment (192.933).
• A process for continual evaluation and assessment (192.937).
• If applicable, a plan for confirmatory direct assessment (192.931).
• Provisions for adding preventive and mitigative measures to protect the high consequence area (192.935).
• A performance plan as outlined in ASME/ANSI B31.8S, Section 9 that includes performance measures meeting the
requirements of 192.943.
• Record keeping provisions (192.947).
• A management of change process as outlined in ASME/ANSI B31.8S, Section 11.
• A quality assurance process as outlined in ASME/ANSI B31.8S, Section 12.
• A communication plan that includes the elements of ASME/ANSI B31.8S, Section 10, and that includes procedures
for addressing safety concerns raised by OPS and a State or local pipeline safety authority when a covered
segment is located in a State where OPS has an interstate agent agreement.
• Procedures for providing (when requested), by electronic or other means, a copy of the operator’s risk analysis or
integrity management program to OPS and a State or local pipeline safety authority when a covered segment is
located in a State where OPS has an interstate agent agreement.
• Procedures for ensuring that each integrity assessment is being conducted in a manner that minimizes
environmental and safety risks.
• A process for identification and assessment of newly-identified high consequence areas. (192.905 and 192.921.)
A fully-developed program involves complete documentation of how each element noted above will be
performed.
FAQ-85. Can pipeline integrity management programs required by Subpart O be part of broader
corporate safety or integrity management systems (e.g., as described in API Publication 9100A,
Model Environmental, Health and Safety (EHS) Management System)? [05/10/2004]
Pipeline integrity management programs must meet the requirements of Subpart O. As long as those
requirements are met, the programs may be part of broader company management systems. Elements of
existing management systems that can meet the requirements of the rule can be incorporated into the
pipeline integrity management program. Alternatively, operators may decide that processes and methods

<<<PAGE 8>>>

used in their pipeline integrity management programs could be useful for other purposes, and may integrate
them into broader company systems. OPS expects to see a description of the pipeline integrity management
program that meets the requirements of the rule. OPS is willing to consider elements of broader company
programs and systems as part of this program description, provided they are sufficiently complete and robust
to meet rule requirements. It is the operator’s responsibility to demonstrate how such existing corporate
management systems meet the requirements of the rule.
FAQ-140. What level of detail does OPS expect to see in initial IM frameworks for each of the
required program elements? [06/09/2004]
The level of detail in the framework will vary depending on the level of maturity of each program element. In
general, OPS expects that elements that must be implemented early will have considerable detail. This
includes identification of all high consequence areas, threat identification, and baseline assessment plans. The
description in the framework of elements that will be implemented later may be more sketchy. These include
a continual process for evaluation and assessment, process for adding preventive and mitigative measures,
and plans for confirmatory direct assessment. OPS would expect a reasonably complete description of the
elements that relate to managing the IM program, e.g., quality assurance, management of change, and
record keeping, although the IM program descriptions of these elements may become more detailed as
experience is gained.
OPS would find unacceptable a situation in which a program element was being actively implemented but
little or no description of that element is included in the IM framework/program. Program elements should
be thought out, documented, and receive the internal approvals the operator considers necessary before
they are implemented.
FAQ-202. DA vendors offer processes that include proprietary analysis techniques (similar to how
ILI vendors use algorithms to classify anomalies). If my IMP written plan has to document my
process for CIS/DCVG/etc. acceptance limits, how can I use vendors that wouldn’t give away
their intellectual property? [12/06/2004]
Operators are responsible for assuring accurate results. OPS expects that operators will have enough
understanding to assure that the process accurately identifies pipeline anomalies and sufficiently assures
pipeline integrity. Operators will need to obtain enough information from their vendors to assure that they
understand the capabilities and limitations of the vendor’s techniques including the tolerances of tools to be
used.
FAQ-238. What documentation must I include in my IM program to describe a "process" required
by the rule? [04/18/2007]
IM program documentation should include sufficient detail that an employee with appropriate experience
and training can follow the procedure/process to achieve the desired objective consistently. The
procedure/process should address, as applicable:
• Who is responsible for completing the process/procedure;
• What are the objectives of the process/procedure;
• What data/information is necessary for completing the process/procedure and where it is acquired;
• How and When are the objectives of the process/procedure to be performed (detailed process/procedure steps);
• How are key steps/results of the process/procedure documented (designated format) and where is the
documentation stored;
• How are process/procedure results communicated to key personnel;
• What is the method for identifying and incorporating process/procedure improvements (reviews/feedback loops)
FAQ-239. How much detail must I include when the rule requires that I "justify" an action or
decision? [08/02/2006]
A documented justification should include technical rationale completely describing the basis or reason for
the decision. It is not sufficient simply to re-state the decision without describing why it was made.
[Top]
HCA Identification FAQ

<<<PAGE 9>>>

FAQ-14. When must covered pipeline segments subject to the rule be identified?[05/19/2004]
All High Consequence Areas (HCAs) must be identified as part of an operator’s initial integrity management
framework, which must be completed by December 17, 2004. OPS will expect to see the operator's process
for identifying HCAs described in the initial framework. The rule allows operators to use existing data on the
density of buildings intended for human occupancy near the pipelines, pro-rating any potential impact circles
larger than 660 feet in radius, until December 17, 2006.
FAQ-15. Many operators have pre-defined segments on their pipeline (e.g., the length of pipe
between two compressor stations or between consecutive isolation valves is considered a
segment). When OPS refers to segments in HCAs in the rule, in what context is the term segment
used? [05/17/2004]
As used in the rule "covered segment" means a continuous segment of pipeline located in an HCA. If the
potential impact circle methodology is used to identify HCAs, then, at a minimum, the covered segment
begins at the outermost edge of the first potential impact circle that meets the HCA criteria and extends
axially to the outermost edge of the last contiguous potential impact circle that meets the HCA criteria. This
length of pipe may be subdivided to facilitate integrity assessments. Examples include such divisions as
pressure limiting stations, pipe size changes or other practical divisions.
FAQ-16. How will an operator determine if a pipeline is in an HCA? [05/19/2004]
The potential impact radius must be calculated along the pipeline using the following formula:
PIR = 0.69 * (p*d2)0.5
Where:
PIR = Potential Impact Radius (in feet)
p = maximum allowable operating pressure (in pounds per square inch)
d = nominal pipeline diameter (in inches), and
0.69 is a constant applicable to natural gas (constants for other gases must be determined in
accordance with Section 3.2 of ASME B31.8S-2001)
Pipeline segments for which the circle defined by the potential impact radius includes 20 or more buildings
intended for human occupancy or an identified site are considered high consequence areas.
Alternatively, Operators may treat all class 3 and 4 locations on their pipelines as high consequence areas. If
they elect to use this option, the use of potential impact circles is limited to looking for identified sites in any
areas of their pipeline which are not class 3 or class 4 or to considering housing density and identified sites in
areas where the potential impact circle radius would exceed 660 feet (i.e., for large-diameter, high- pressure
pipelines).
Operators can select either method for use on their entire pipeline system, or may use each method only on
selected portions of their pipeline.
FAQ-17. What is an identified site? [05/19/2004]
An identified site is an area where people congregate near the pipeline meeting one of three criteria:
• It is an outside area or open structure occupied by 20 or more persons on more than 50 days in any
12-month period (the days need not be consecutive).
• It is a building occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month
period (the days and weeks need not be consecutive), or
• It is a facility occupied by persons of limited mobility, e.g., hospitals, prisons, day-care facilities, schools,
retirement communities or assisted living centers.
FAQ-18. Are there practical limits on an operator’s search for identified sites?[05/17/2004]
Yes. An operator is expected to make a reasonable effort to identify sites meeting the criteria for "identified
sites". The rule requires that operators consider information they glean from routine operations and
maintenance activities along the pipeline and from public officials responsible for safety or emergency
response/planning who indicate to the operator that they would know of locations near the pipeline meeting
these criteria. If no public officials have such knowledge, then the operator must identify facilities that
either: have visible signs; are licensed by a Federal, State, or local government agency; or appear on a list

<<<PAGE 10>>>

or map available from such an agency. See OPS’s Advisory Bulletin ADB-03-03 dated July 17, 2003,
(available on this web site -- http://primis.phmsa.dot.gov/gasimp under "key documents") for additional
guidance.
FAQ-19. What are OPS expectations for operators to determine new or changed
HCAs? [05/17/2004]
Operators must continually monitor conditions along their pipeline. When they become aware of population
or usage changes that create or change an HCA (e.g., population expands to encompass more of the area
near the pipeline right-of-way), this information should be factored, at least once per calendar year, into
their integrity assessment planning, risk analysis, and consideration of the need for additional preventive
and mitigative risk controls.
FAQ-20. When must newly-identified HCAs be included in the program?[08/17/2004]
Over time, new HCAs may be identified, such as when population distributions change or new sites that are
occupied by 20 or more persons are identified. Operators must consider such changes to determine whether
new HCAs have been created. A newly-identified HCA must be incorporated into the integrity management
program (including the baseline assessment plan) within one year of its identification. A baseline assessment
for pipeline segments in newly identified HCAs must be performed within ten years of its identification.
FAQ-21. Must non-pipe elements of a pipeline system in HCAs (e.g., compressor stations) be
identified by 12/17/04? [05/17/2004]
Yes. While the assessment requirements of 49 CFR 192 Subpart O are applicable to line pipe, all other
requirements, including covered segment identification, are applicable to the entire pipeline, which is defined
in 49 CFR 192.3 as all parts of those physical facilities through which gas moves in transportation. OPS
expects operators to understand which compressor stations and other facilities meet criteria to be treated as
covered segments in HCAs.
FAQ-22. Why is it important that operators know the specific characteristics of high consequence
areas their pipelines traverse? [08/14/2006]
Operators need to know the characteristics of HCAs along their pipeline to make decisions required by the
integrity management rule. For example, the number/nature of housing units (e.g., large apartment
buildings) can affect the consequences of a leak or rupture, and thus affect the relative risk ranking of a
segment or decisions regarding preventive and mitigative measures. Section 3.3 of ASME/ANSI B31.8S
specifies additional consequence factors to consider, including security of gas supply, public convenience and
necessity, and the potential for secondary failures.
FAQ-117. How often must an operator update its building density survey and list of identified
sites to determine if new HCAs have been created? [06/09/2004]
The rule does not specify a frequency for updating data used to identify HCAs. Instead, the rule states that
operators must complete an evaluation when they have information that the area around a segment not
previously identified as an HCA has changed so that it might now be one. Operators are expected to assure
that their HCA definitions are current. In an area in which there is rapid growth or change in the use of
buildings near the pipeline, that may require frequent updating. In an area where less growth is occurring,
updates could occur more infrequently. In any event, OPS would expect that operators would evaluate
conditions along their pipelines at least annually to determine if they have changed.
FAQ-119. Can I use normal operating pressure in my potential impact circle calculations if that
pressure is significantly below MAOP? [05/11/2004]
No. The rule requires that MAOP be used in calculating potential impact circles (PIC) to identify HCAs.
Pipelines can operate up to their MAOP, and integrity must be assured for such operation. Operators whose
MAOP is significantly higher than their operating pressure could choose to derate their pipeline to reduce the
calculated size of PICs. In such a case, subsequent increases in MAOP would be subject to the requirements
of Subpart K for uprating and would require that PICs be re-calculated.
FAQ-120. Who is an appropriate safety authority for locating identified sites?[05/17/2004]
Section 192.905 requires that information on identified sites be obtained from "public officials with safety or
emergency response or planning responsibilities". That section also states that this "could include officials on

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a local emergency planning commission or relevant Native American tribal officials." The precise titles of the
appropriate officials are likely to vary from community to community. They may include the fire chief, or
equivalent, or public officials who would be responsible for evacuations in the event of a natural disaster.
Each operator is responsible for identifying appropriate public officials. If an operator cannot locate public
officials who can provide information about locations meeting the criteria for identified sites, then the
operator must use one of the other methods identified in Section 192.905 to locate them. See OPS’ Advisory
Bulletin ADB-03-03 dated July 17, 2003, (available on this web
site, http://primis.phmsa.dot.gov/gasimp/, under "key documents") for additional guidance.
FAQ-121. Must facilities occupied by an operator's employees be considered in identifying
HCAs? [05/11/2004]
Yes. The rule is intended to provide enhanced protection for gatherings of people, and gatherings of operator
employees are expected to gain the same enhanced protection. Areas, including buildings and facilities,
where operator employees gather in sufficient numbers and on a sufficient number of days to meet criteria in
the definition of HCAs should be so classified.
FAQ-143. When determining "identified sites", does one have to consider standing traffic on
roads/expressways under the "outside area or open structure" portion of the definition? If so, is
there any guidance on how many people per vehicle should be used to compute the total of
20? [02/20/2004]
Identified sites are defined as areas that are "occupied" by more than 20 persons for specified periods. While
roads and expressways near pipelines could well carry enough traffic that more than 20 persons are in
proximity to the pipeline at one time, these travelers can not be said to "occupy" that location. The definition
of identified sites is intended to provide additional protection for areas where people stay for more than a few
seconds or minutes. Most roads and expressways need not b
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