# ENSTAR NATURAL GAS CO — Notice of Amendment

- **operation:** document
- **citation:** CPF 520080009M
- **title:** ENSTAR NATURAL GAS CO — Notice of Amendment
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2008-04-23
- **effective on:** Not available
- **summary:** CLOSED notice of amendment citing 192.7(a), 192.907, 192.907(a), 192.911, 192.911(i), 192.911(k), 192.911(m), 192.915, 192.915(a), 192.915(b), 192.915(c), 192.917, 192.917(e)(1), 192.919, 192.919(c), 192.923, 192.925(b), 192.925(b)(1), 192.925(b)(2), 192.925(b)(3), 192.933, 192.933(a), 192.933(b), 192.933(c), 192.933(d), 192.935(a), 192.937(a), 192.939, 192.945, 192.945(a), 192.945(b).
- **machine formats:** - **json:** https://regulus.evalyn.ai/document/phmsa-enforcement-520080009m.json
- **markdown:** https://regulus.evalyn.ai/document/phmsa-enforcement-520080009m.md
- **app url:** https://regulus.evalyn.ai/document/phmsa-enforcement-520080009m
- **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/520080009M
**body:**

Notice of Amendment involving ENSTAR NATURAL GAS CO. PHMSA's enforcement data identifies the cited regulations as 192.7(a),  192.907,  192.907(a),  192.911,  192.911(i),  192.911(k),  192.911(m),  192.915,  192.915(a),  192.915(b),  192.915(c),  192.917,  192.917(e)(1),  192.919,  192.919(c),  192.923,  192.925(b),  192.925(b)(1),  192.925(b)(2),  192.925(b)(3),  192.933,  192.933(a),  192.933(b),  192.933(c),  192.933(d),  192.935(a),  192.937(a),  192.939,  192.945,  192.945(a),  192.945(b). The case was opened on 2008-04-23 and is reported as closed as of 2008-07-23. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

520071009M_operator response_07102007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520080009M/520071009M_operator%20response_07102007.pdf

520080009M_notice of amendment_04232008.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520080009M/520080009M_notice%20of%20amendment_04232008.pdf

520080009m_notice of amendment_04232008_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520080009M/520080009m_notice%20of%20amendment_04232008_text.pdf

520080009M_operator response to notice_05212008.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520080009M/520080009M_operator%20response%20to%20notice_05212008.pdf

520080009m_notice of amendment_04232008_text.pdf

U. S. Department
of Transportation
Pipeline and
Hazardous Materials Safety
Administration
12300 W Dakota Ave, Suite 110
Lakewood, CO 80228
NOTICE OF AMENDMENT
CERTIFIED MAIL - RETURN RECEIPT RE UESTED
April 23, 2008
Mr John Lau
Director, Transmission Operations
Alaska Pipehne Company
401 E. International Airport Road
P. O Box 190288
Anchorage, AK 99519-0288
CPF 5-2008-0009M
Dear Mr. Lau
On May 7-11, 2007, representatives of the Pipehne and Hazardous Materials Safety
Admmistration (PHMSA), pursuant to Chapter 601 of 49 United States Code, mspected your
integrity management program in Anchorage, Alaska.
As a result of the inspection, it appears that your wntten procedures are madequate to assure safe
operation of the pipeline as follows:
g 192. 905 How does an operator identify a high consequence area?
(b)(1) Identified sites. An operator must identify an identified site, for purposes of this
subpart, from information the operator has obtained from routine operation and
maintenance activities and from public officials with safety or emergency response or
planning responsibilities who indicate to the operator that they know of locations that
meet the identified site criteria. These public officials could include officials on a local
emergency planning commission or relevant Native American tribal officials.
g 192. 907 What must an operator do to implement this subpart?



(a) General. No later than December 17, 2004, an operator of a covered pipeline
segment must develop and follow a written integrity management program that
contains all the elements described in g 192. 911 and that addresses the risks on each
covered transmission pipeline segment.
1 a) Alaska Pipehne Company (APC) does not provide adequate procedures for the
documentation of field verification of identified sites. As an example, AS&G offices in
Area A7 were excluded as an identified site m 2004, but included as an identified site in
2006 The annual review for 2005 stated that the identified sites were verified" but there
is no mdication of the depth of that verification process In addition, field data varies m its
depth based primarily on the personnel performmg the venfication
lb) APC documents the defimtions of identified sites and the methods for their
identification m a memorandum that is not referenced by its procedures or program
document,
g 192. 911 'What are the elements of an integrity management program?
An operator's initial integrity management program begins with a framework (see $
192. 907) and evolves into a more detailed and comprehensive integrity management
program, as information is gained and incorporated into the program. An operator
must make continual improvements to its program. The initial program framework
and subsequent program must, at minimum, contain the following elements. (When
indicated, refer to ASME/ANSI B31. 8S (ibr, see g 192. 7) for more detailed
information on the listed element. )
(k) A management of change process as outlined in ASME/ANSI B31. 8S, section 11.
g 192. 919 What must be in the baseline assessment plan?
An operator must include each of the following elements in its written baseline
assessment plan:
(c) A schedule for completing the integrity assessment of all covered segments,
including risk factors considered in establishing the assessment schedule;
2a) The APC process for developmg the BAP does not provide requirements for keepmg
the BAP up-to-date with respect to newly arismg information, apphcable threats, and risks
that may require changes to the segment prioritization or assessment method
g 192. 907 What must an operator do to implement this subpart?
(a) General. No later than December 17, 2004, an operator of a covered pipeline
segment must develop and follow a written integrity management program that
contains aB the elements described in g 192, . 911 and that addresses the risers on each
covered transmission pipeline segment.



(b) Implementation Standards. In carrying out this subpart, an operator must follow
the requirements of this subpart and of ASME/ANSI B31. 8S (ibr, see $ 192. 7) and its
appendices, where specified. An operator may follow an equivalent standard or
practice only when the operator demonstrates the alternative standard or practice
provides an equivalent level of safety to the public and property. In the event of a
conflict between this subpart and ASMK/ANSI B31. 8S, the requirements in this
subpart control.
g 192. 917 How does an operator identify potential threats to pipeline integrity and
use the threat identification in its integrity program?
(a) Threat identification. An operator must identify and evaluate all potential threats
to each covered pipeline segment. Potential threats that an operator must consider
include, but are not limited to, the threats listed in ASMK/ANSI B31. 8S (ibr, see g
192. 7), section 2, which are grouped under the following four categories: (1) Time
dependent threats such as internal corrosion, external corrosion, and stress corrosion
cracking; (2) Static or resident threats, such as fabrication or construction defects; (3)
Time independent threats such as third party damage and outside force damage; and
(4) Human error.
(b) Data gathering and integration. To identify and evaluate the potential threats to a
covered pipeline segment, an operator must gather and integrate existing data and
information on the entire pipeline that could be relevant to the covered segment. In
performing this data gathering and integration, an operator must follow the
requirements in ASMK/ANSI B31. 8S, section 4. At a minimum, an operator must
gather and evaluate the set of data specified in Appendix A to ASME/ANSI B31. 8S,
and consider both on the covered segment and similar non-covered segments, past
incident history, corrosion control records, continuing surveillance records,
patrolling records, maintenance history, internal inspection records and all other
conditions specific to each pipeline.
(c) Risk assessment. An operator must conduct a risk assessment that follows
ASME/ANSI B31. 8S, section 5, and considers the identified threats for each covered
segment. An operator must use the risk assessment to prioritize the covered segments
for the baseline and continual reassessments (gg 192. 919, 192. 921, 192. 937), and to
determine what additional preventive and mitigative measures are needed (g 192. 935)
for the covered segment.
3a) There are no procedures to require documentmg the threat analysis performed by APC
No documented basis exists for the exclusion of cychc fatigue or other threats, and no
evaluation is provided for apphcable threats.
3b) APC has not used a conservative approach m its data analysis regardmg the fact that
there is an absence of records to demonstrate that pre-1970 piping is not low frequency
ERW pipmg
3c) There are madequate procedures to ensure that the APC risk assessment supports the
ob]ectives identified in Sections 5. 3 and 5. 4 of ASME B32. 8S-2001



3d) The APC IMP does not have a documented process for vahdatmg &ts nsk assessment
4. g 192. 917 How does an operator identify potential threats to pipeline integrity and
use the threat identification in its integrity program?
(e) Actions to address particuLar threats. If an operator identifies any of the following
threats, the operator must take the following actions to address the threat. (1) Third
party damage. An operator must utilize the data integration required in paragraph (b)
of this section and ASME/ ANSI B31. 8S, Appendix A7 to determine the susceptibility
of each covered segment to the threat of third party damage. If an operator identifies
the threat of third party damage, the operator must implement comprehensive
additional preventive measures in accordance with $192. 935 and monitor the
effectiveness of the preventive measures. If, in conducting a baseline assessment
under $192. 921, or a reassessment under )192. 937, an operator uses an internal
inspection tool or external
g 192. 923 How is direct assessment used and for what threats?
(a) General. An operator may use direct assessment either as a primary assessment
method or as a supplement to the other assessment methods allowed under this
subpart. An operator may only use direct assessment as the primary assessment
method to address the identified threats of external corrosion (ECDA), internal
corrosion (ICDA), and stress corrosion cracking (SCCDA). (b) Primary method. An
operator using direct assessment as a primary assessment method must have a plan
that complies with the requirements in — (1) ASME/ANSI B31. 8S (ibr, see $192. 7),
section 6. 4; NACE RP0502 — 2002 (ibr, see g 192. 7); and g 192. 925 if addressing
external corrosion (ECDA).
g 192. 925 'What are the requirements for using External Corrosion Direct Assessment
(ECDA)?
(b) General requirements. An operator that uses direct assessment to assess the threat
of external corrosion must follow the requirements in this section, in ASME/ANSI
B31. 8S (ibr, see g 192. 7), section 6. 4, and in NACE RP 0502 — 2002 (ibr, see g 192. 7).
An operator must develop and implement a direct assessment plan that has
procedures addressing preassessment, indirect examination, direct examination, and
post-assessment. If the ECDA detects pipeline coating damage, the operator must also
integrate the data from the ECDA with other information from the data integration
(g 192. 917(b)) to evaluate the covered segment for the threat of third party damage,
and to address the threat as required by g 192. 917(e)(1).
(1) Preassessment. In addition to the requirements in ASME/ANSI B31. 8S section 6. 4
and NACE RP 0502 — 2002, section 3, the plan's procedures for preassessment must
include—
(i) Provisions for applying more restrictive criteria when conducting ECDA for the
first time on a covered segment.



(") h b
ii The basis on w ic an o
h' h an operator selects at least two different, but complementary
indirect assessment tools to assess each ECDA Reg' . p
e ion. If an o erator utilizes an
indirect ins ection method that is not discussed in Appendix A of NACE RP0502—
2002, the operator must demonstrate the applica i i y, va i a i
' '
used, application proce ure, an u
d d tilization of data for the inspection method.
(2) Indirect Examination. In addition to the requiremen irements in ASME/ANSI B31. 8S
section 6. 4 and NACE RP 0502 — 2002, section 4, the plan's procedures for indirect
examination of the ECDA regions must include—
(i) Provisions for applying more restrictive criteria w hen conductin ECDA for the
first time on a covered segment;
ii Criteria for identifying and documenting those indications that must be
e
ed for excavation and iree examin
' d d' t mination. Minimum identification criteria
include the known sensitivities of assessment too s, e proce
ls the rocedures for using each tool,
'
and the approach to be used for decreasing the h sical s acing of indirect
p y
p
assessment tool readings when the presence of a defect is suspected;
(iii) Criteria for defining the urgency of excava io
f excavation and direct examination of each
ified durin the indirect examination. These criteria must speci y ow
an operator will define the urgency of excavating the indication as imme ia e,
scheduled or monitored; and
(iv) Criteria for scheduling excavation of indications for each urgency level.
t. In addition to the requirements in ASME/ANSI B31. 8S section
6. 4 and NACE RP 0502 — 2002, section 5, the plan's procedures for iree exam'
of indications from the indirect examination must include—
(i) Provisions for applying more restrictive criteria whe n conductin ECDA for the
first time on a covered segment;
(ii) Criteria for deciding what action should be taken if either:
(A) Corrosion defects are discovered that exceed allow able limits (Section 5. 5. 2. 2 of
NACE RP0502 — 2002), or
(B) Root cause analysis reveals conditions for whic
hich ECDA is not suitable (Section
5. 6. 2 of NACE RP0502 — 2002).
(iii) Criteria and notification procedures for any g
chan es in the ECDA Plan,
inclu ing c anges
I d' h s that affect the severity classification, the priority of direct
examination and the time frame or ire
for ire ' ' ' '
s and iv)
Czlterla that descrlbeho% and onw a asls 59. f ~ACE~0502
reprioritize any of the y rovisions t at are s ecifierl in section
2002.



(4) Post assessmeni and continuing evaluation. In addition to the requirements in
ASMEIANSI B31. 8S section 6. 4 and NACE RP 0502 — 2002, section 6, the plan's
procedures for post assessment of the effectiveness of the ECDA process must
include—
(i) Measures for evaluating the long-term effectiveness of ECDA in addressing
external corrosion in covered segments;
and
(ii) Criteria for evaluating whether conditions discovered by direct examination of
indications in each ECDA region indicate a need for reassessment of the covered
segment at an interval less than that specified in g 192. 939. (See Appendix D of NACE
RP 0502 — 2002. )
~ Item 4A: g 192. 923 and g 192. 925(b)
The APC ECDA Procedure does not specify as a mmimum types of records identified m
NACE section 3 as records to be obtamed during the pre-assessment phase of ECDA.
~ Item 4B: g 192. 923 and g 192. 925(b)(1)
The APC IMP does not require that the basis for indirect exammation tool selection be
documented and the basis is not provided m IMP records.
~ Item 4C: g 192. 923 and g 192. 925(b)(1)
The APC ECDA Plan does not specify the more restrictive criteria to be applied durmg the
pre-assessment phase of the ECDA process
~ Item 4D: g 192. 917(e)(1), g 192. 923 and g 192. 925(b)
The APC ECDA Plan provides no procedures for the mtegration of ECDA data with
foreign lme crossings or encroachments
~ Item 4E: g 192. 923 and g 192. 925(b)(2)
APC has not documented nor apphed more restrictive criteria during the mdirect
exammation step of its ECDA process
~ Item 4F: g 192. 923 and g 192. 925(b)(3)
APC has no documented process for determimng the root cause of significant corrosion
activity, nor is there any method documented for examining the imphcations of sigmficant
corrosion activity to other sections of the pipehne
~ Item 4G: g 192. 923 and g 192. 925(b)(3)



The APC ECDA Plan does not require documentation of the basis upon which mdications
are reclassified and reprioritized in accordance with any of the provisions that are specified
m NACE RP0502-2002, Section 5 9
~ Item 4H: g 192. 923, g 192. 925(b)(4) and g 192. 939
The APC IMP does not contam provisions for the performance of remammg hfe
calculations to determme the appropriate reassessment mtervals for its HCA pipelme
segments
~ Item 4I: g 192. 923, g 192. 925(b)(4) and g 192. 939
The APC IMP does not specify any criteria for evaluating whether conditions discovered
by direct exammation of mdications mdicate a need for reassessment at an interval less
than specified m 192 939.
~ Item 4J: g 192. 923, g 192. 925 and g 192. 945(b)
APC has not estabhshed or monitored additional criteria to evaluate long-term ECDA
program effectiveness.
~ Item 4K: g 192. 907(a) and $ 192. 923
The APC IMP processes have not mcorporated feedback mechamsms that enable
contmuous improvement of the ECDA Plan.
5. Remediation
g 192. 907 What must an operator do to implement this subpart?
(a) General. No later than December 17, 2004, an operator of a covered pipeline
segment must develop and follow a written integrity management program that
contains all the elements described in g 192. 911 and that addresses the risks on each
covered transmission pipeline segment.
g 192. 933 What actions must be taken to address integrity issues?
(a) General requirements An operator must take prompt action to address all
anomalous conditions that the operator discovers through the integrity assessment. In
addressing all conditions, an operator must evaluate all anomalous conditions and
remediate those that could reduce a pipeline's integrity. An operator must be able to
demonstrate that the remediation of the condition will ensure that the condition is
unlikely to pose a threat to the integrity of the pipeline until the next reassessment of
the covered segment. If an operator is unable to respond within the time limits for
c'H(Qii cM'54Ms sgccYGc6 %% Gals sec4M, the opeva(ov mesc cemyovavily veh~ce the
oyerating yressure of the pipeline or take other action that ensures the safety of the
covered segment. If pressure is re uce, duced an operator must determine the temporary



reduction in operating pressure using ASME/ANSI B31G (ibr, see g 192. 7) or AGA
Pipeline Research Committee Project PR — 3 — 805 ("RSTRENG", ibr, see g 192. 7) or
reduce the operating pressure to a level not exceeding 80% of the level at the time the
condition was discovered. (See appendix A to this part 192 for information on
availability of incorporation by reference information). A reduction in operating
pressure cannot exceed 365 days without an operator providing a technical
justification that the continued pressure restriction will not jeopardize the integrity of
the pipeline.
(b) Discovery of condition. Discovery of a condition occurs when an operator has
adequate information about a condition to determine that the condition presents a
potential threat to the integrity of the pipeline. A condition that presents a potential
threat includes, but is not limited to, those conditions that require remediation or
monitoring listed under paragraphs (d)(1) through (d)(3) of this section. An operator
must promptly, but no later than 180 days after conducting an integrity assessment,
obtain sufficient information about a condition to make that determination, unless
the operator demonstrates that the 180-day period is impracticable.
(c) Schedule for evaluation and remediation. An operator must complete remediation
of a condition according to a schedule that prioritizes the conditions for evaluation
and remediation. Unless a special requirement for remediating certain conditions
applies, as provided in paragraph (d) of this section, an operator must follow the
schedule in ASME/ANSI B31. 8S (ibr, see $192. 7), section 7, Figure 4. If an operator
cannot meet the schedule for any condition, the operator must justify the reasons why
it cannot meet the schedule and that the changed schedule will not jeopardize public
safety.
(d) Special requirements for scheduling remediation. —
(3) Monitored conditions. An operator does not have to schedule the following
conditions for remediation, but must record and monitor the conditions during
subsequent risk assessments and integrity assessments for any change that may
require remediation:
(i) A dent with a depth greater than 6% of the pipeline diameter (greater than 0. 50
inches in depth for a pipeline diameter less than NPS 12) located between the 4
o' clock position and the 8 o' clock position (bottom 1/3 of the pipe).
(ii) A dent located between the 8 o' clock and 4 o' clock positions (upper 2 /3 of the
pipe) with a depth greater than 6% of the pipeline diameter (greater than 0. 50 inches
in depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12), and
engineering analyses of the dent demonstrate critical strain levels are not exceeded.
(iii) A dent with a depth greater than 2% of the pipeline's diameter (0. 250 inches in
depth for a pipeline diameter less than NPS 12) that affects gee curvature at a girth
weM or a longitudinal seam weM, and engineering analyses of the dent and girth or
seam weld demonstrate critical strain levels are uot exceeded. These analyses must
consider weld properties.



~ Item 5A: g 192. 907 and g 192. 933(b)
The APC IMP does not provide a definition for discovery that defines when sufficient
mformation is available to determme the significance of an anomaly.
~ Item 5B: g 192. 907 and g 192. 933(b)
The APC IMP does not provide adequate procedures specifymg how the date of discovery
is to be documented.
~ Item 5C: g 192. 907 and g 192. 933(d)
The APC IMP does not require that a temporary pressure reduction or shutdown of the
pipehne occur upon discovery of all immediate repair conditions
~ Item 5D: g 192. 907 and g 192. 933(d)
The APC IMP does not have adequate procedures for recording and trackmg anomahes
identified as monitored conditions.
~ Item 5E: g 192. 907 and g 192. 933(a)
The APC IMP has no program procedures identifymg the appropriate actions to take when
remediation timeframes cannot be met
~ Item 5F: g 192. 907 and g 192. 933(c)
The APC IMP has no program procedures identifymg the appropriate actions to take to
~ustify why a schedule cannot be met and why a schedule change will not jeopardize pubhc
safety.
~ Item SG: g 192. 907 and g 192. 933(c)
The APC IMP has no program requirements to specify how notification is to be
accomphshed m the event the operator cannot meet the remediation schedule or provide a
temporary reduction in operating pressure
6. Continual Evaluation and Assessment
g 192. 937 What is a continual process of evaluation and assessment to maintain a
pipeline's integrity?
(a) Gezzeral. After completing the baseline integrity assessment of a covered segment,
M QQ'H'l(M MESC CQYi4YlM, %0 'Assess 6M one pipe oY that segment at the tntevvats
specified in g 192. 939 and periodically evaluate the integrity of each covered pipeline
segment as provided in paragraph (b) of this section. An operator must reassess a



covered segment on which a prior assessment is credited as a baseline under g
192. 921(e) by no later than December 17, 2009. An operator must reassess a covered
segment on which a baseline assessment is conducted during the baseline period
specified in g 192. 921(d) by no later than seven years after the baseline assessment of
that covered segment unless the evaluation under paragraph (b) of this section
indicates earlier reassessment.
~ Item 6A: g 192. 937(a)
The APC IMP has no procedures to determme if an earlier reassessment is necessary than
that required by 192 939
7. Preventive and Mitigative Measures
g 192. 907 What must an operator do to implement this subpart?
(a) General. No later than December 17, 2004, an operator of a covered pipeline
segment must develop and follow a written integrity management program that
contains all the elements described in g 192. 911 and that addresses the risks on each
covered transmission pipeline segment.
g 192. 917 How does an operator identify potential threats to pipeline integrity and
use the threat identification in its integrity program?
(e) ActioIis to address particular threats. If an operator identifies any of the following
threats, the operator must take the following actions to address the threat.
(5) Corrosion. If an operator identifies corrosion on a covered pipeline segment that
could adversely affect the integrity of the line (conditions specified in g 192. 933, the
operator must evaluate and remediate, as necessary, all pipeline segments (both
covered and non-covered) with similar material coating and environmental
characteristics. An operator must establish a schedule for evaluating and
remediating, as necessary, the similar segments that is consistent with the operator's
established operating and maintenance procedures under part 192 for testing and
repair.
g 192. 935 What additional preventive and mitigative measures must an operator
take?
(a) General requirements. An operator must take additional measures beyond those
already required by Part 192 to prevent a pipeline failure and to mitigate the
consequences of a pipeline failure in a high consequence area. An operator must base
the additional measures on the threats the operator has identified to each pipeline
segment. (See g 192. 917) An operator must conduct, in accordance with one of the
risk assessment approaches in ASMK/ANSI B31. 8S (ibr, see g 192. 7), section 5, a risk
analysis of its pipeline to identify additional measures to protect the high consequence
area and enhance public safety. Such additional measures include, but are not limited
to, installing Automatic Shut-off Valves or Remote Control Valves, installing
10



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.
~ Item 7A: g 192. 907, g 192. 917(e)(5), and ) 192. 935(a)
The APC IMP has no documented process to check for the potential threats of internal
corrosion or SCC
~ Item 7B: g 192. 907 and g 192. 935(a)
The APC IMP has no documented, systematic, decision-makmg process for decidmg
which P&M measures are to be implemented
8. Performance Measures
g 192. 945 What methods must an operator use to measure program effectiveness'?
(a) General. An operator must include in its integrity management program methods
to measure, on a semi-annual basis, whether the program is effective in assessing and
evaluating the integrity of each covered pipeline segment and in protecting the high
consequence areas. These measures must include the four overall performance
measures specified in ASME/ANSI B31. 8S (ibr, see f192. 7), section 9. 4, and the
specific measures for each identified threat specified in ASME/ANSI B31. 8S,
Appendix A. An operator must submit the four overall performance measures, by
electronic or other means, on a semi-annual frequency to OPS in accordance with
$192. 951. An operator must submit its first report on overall performance measures
by August 31, 2004. Thereafter, the performance measures must be complete through
June 30 and December 31 of each year and must be submitted within 2 months after
those dates.
~ Item 8A: g 192. 945(a)
The APC performance measure report endmg 12/31/04 was submitted to PHMSA on
3/09/05 (nme days late)
9. Management of Change
g 192. 909 How can an operator change its integrity management program.
(a) General. An operator must document any change to its program and the reasons
for the change before implementing the change.
g 192. 911 What are the elements of an integrity management program?
11



An operator's initial integrity management program begins with a framework (see g
192. 907) and evolves into a more detailed and comprehensive integrity management
program, as information is gained and incorporated into the program. An operator
must make continual improvements to its program. The initial program framework
and subsequent program must, at minimum, contain the following elements. (When
indicated, refer to ASME/ANSI B31. 8S (ibr, see g 192. 7) for more detailed
information on the listed element. )
(k) A management of change process as outlined in ASME/ANSI B31. 8S, section 11.
~ Item 9A: g 192. 909(a) and g 192. 911(k)
The APC Management of Change Process does not fully implement the requirements of
the Rule and the referenced ASME B 318S, Section 11 requirements The following are
specific areas noted
o Inadequate documentation of the reason for changes prior to implementation,
o No documented criteria for what constitutes a sigmficant program change for the
purpose of notifymg PHMSA,
o Inadequate procedures to consider impacts of changes to pipehne systems and their
integrity;
o MOC procedures do not address all of the nme basic elements of the change process as
defined m ASME B31. 8S,
o Physical pipeline system changes are not addressed by the MOC process and are not
therefore evaluated for their potential impact on the IMP,
o Procedures do not require that equipment or system changes are identified and
reviewed before implementation
10. Quality Assurance
g 192. 7 Incorporation by reference.
(a) Any documents or portions thereof incorporated by reference in this part are
included in this part as though set out in full. When only a portion of a document is
referenced, the remainder is not incorporated in this part.
g 192. 911 What are the elements of an integrity management program?
An operator's initial integrity management program begins with a framework (see g
192. 907) and evolves into a more detailed and comprehensive integrity management
program, as information is gained and incorporated into the program. An operator
must make continual improvements to its program. The initial program framework
and subsequent program must, at minimum, contain the following elements. (When
indicated, refer to ASME/ANSI B31. 8S (ibr, see g 192. 7) for more detailed
information on the listed element. )
(i) A quality assurance process as outlined in ASMK/ANSI B31. 8S, section 12.
12



$ 192. 915 What knowledge and training must personnel have to carry out an integrity
management program?
(a) Supervisory personnel. The integrity management program must provide that each
supervisor whose responsibilities relate to the integrity management program
possesses and maintains a thorough knowledge of the integrity management program
and of the elements for which the supervisor is responsible. The program must
provide that any person who qualifies as a supervisor for the integrity management
program has appropriate training or experience in the area for which the person is
responsible.
(b) Persons who carry out assessments and evaluate assessment results. The integrity
management program must provide criteria for the qualification of any person—
(1) Who conducts an integrity assessment allowed under this subpart; or (2) Who
reviews and analyzes the results from an integrity assessment and evaluation; or (3)
Who makes decisions on actions to be taken based on these assessments.
(c) Persons responsible for preventive and mitigative measures. The integrity
management program must provide criteria for the qualification of any person — (1)
Who implements preventive and mitigative measures to carry out this subpart,
including the marking and locating of buried structures; or (2) Who directly
supervises excavation work carried out in conjunction with an integrity assessment.
~ Item 10A: g 192. 911(l)
APC does not have a documented Quahty Assurance Plan, therefore, no annual review of a
QA Plan is bemg performed
~ Item 10B: g 192. 911(l)
APC does not have a documented process by which corrective actions for identified
program weaknesses are tracked to completion and vahdated as effective
~ Item 10C: g 192. 911(l)
APC does not have processes to ensure vendor supphed services meet quality requirements
and these processes are not documented as part of a quahty program
~ Item 10D: g 192. 915(a)
The APC IMP does not identify quahfication requirements for supervisory personnel and
does not estabhsh that these personnel meet these requirements Note This is specific to
quahfications beyond those provided by the OQ program.
~ Item 10K: $ 192, . 915(b)
13



The APC IMP does not provide quahfication requirements or evidence of trammg to meet
these requirements for personnel evaluatmg assessment results nor for personnel who
perform activities withm the Integrity Management Program
~ Item 10F: g 192. 915(c)
Quahfications for three APC lme locators have lapsed with respect to required training for
Abnormal Operating Conditions.
~ Item 10G: g 192. 7(a)
APC has not documented its position with regard to "should" statements appearing in
codes and standards.
11. Communications Plan
g 192. 911 What are the elements of an integrity management program?
An operator's initial integrity management program begins with a framework (see g
192. 907) and evolves into a more detailed and comprehensive integrity management
program, as information is gained and incorporated into the program. An operator
must make continual improvements to its program. The initial program framework
and subsequent program must, at minimum, contain the following elements. (When
indicated, refer to ASME/ANSI B31. 8S (ibr, see g 192. 7) for more detailed
information on the listed element. )
(m) A communication plan that includes the elements of ASME/ANSI B31. 8S, section
10, and that includes procedures for addressing safety concerns raised by—
(1) OPS; and (2) A State or local pipeline safety authority when a covered segment is
located in a State where OPS has an interstate agent agreement.
~ Item 11A: g 192. 11(m)
The APC IMP does not contam provision to address safety concerns raised by PHMSA as
appropriate
Res onse to this Notice
This Notice is provided pursuant to 49 U. S. C. ( 60108(a) and 49 C. F. R. ( 190 237 Enclosed as
part of this Notice is a document entitled Response Options for Pipeline Operators in Compliance
Pi"oceeCkngs. Please refer to this document and note the response options Be advised that all
material you submit m response to this enforcement action is subject to being made pubhcly
available If you believe that any portion of your responsive material quahfies for confidential
treatment under 5 U. S C 552(b), along with the complete origmal document you must provide a
SCCDQh CD' D( 5e hocumertt, whh the Iior6ons you beheve quabfy for confidential treatment
re ac e an
d t d d an explanation of why you beheve the redacted mformation quahfies for confidential
treatment under 5 U. S C 552(b) If ou do not respond withm 30 days of receip
14



this constitutes a waiver of your right to contest the allegations m this Notice and authorizes the
Associate Admmistrator for Pipeline Safety to find facts as alleged m this Notice without further
notice to you and to issue a Final Order
If, after opportunity for a hearing, your plans or procedures are found inadequate as alleged in this
Notice, you may be ordered to amend your plans or procedures to correct the inadequacies (49
C F R. ) 190. 237). If you are not contestmg this Notice, we propose that you submit your
amended procedures to my office withm 30 days of receipt of this Notice. This period may be
extended by written request for good cause Once the inadequacies identified herein have been
addressed in your amended procedures, this enforcement action will be closed
In correspondence concerning this matter, please refer to CPF 5-2008-0009M and, for each
document you submit, please provide a copy in electronic format whenever possible.
Smcerely,
Chris Hoidal
Director, Western Region
Pipehne and Hazardous Materials Safety Admmistration
cc PHP-60 Comphance Registry
PHP-500 J Strawn (¹118987)
Enclosure' Response Options for Pipeline Operators in Compliance ProceeCkngs
15
- **truncated:** false
- **body characters:** 35682