# GULF SOUTH PIPELINE COMPANY, LLC — Notice of Probable Violation

**Citation:** CPF 420071003  
**Type / status:** enforcement / historical  
**Agency:** Pipeline and Hazardous Materials Safety Administration  
**Effective:** Not stated  
**Published:** 2007-03-27

CLOSED notice of probable violation citing 192.605(b)(1), 192.909(a), 192.911(k), 192.911(l), 192.911(m), 192.915, 192.917(a), 192.917(b), 192.917(c), 192.917(e)(3), 192.919(b), 192.921, 192.921(a)(1), 192.933(c), 192.935(a), 192.935(c), 192.937(b).

## Document text

Notice of Probable Violation involving GULF SOUTH PIPELINE COMPANY, LLC. PHMSA's enforcement data identifies the cited regulations as 192.605(b)(1),  192.909(a),  192.911(k),  192.911(l),  192.911(m),  192.915,  192.917(a),  192.917(b),  192.917(c),  192.917(e)(3),  192.919(b),  192.921,  192.921(a)(1),  192.933(c),  192.935(a),  192.935(c),  192.937(b). The case was opened on 2007-03-27 and is reported as closed as of 2012-05-30. Proposed civil penalty: $183,000. Assessed civil penalty: $85,800. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

420071003_Closure_05302012.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071003/420071003_Closure_05302012.pdf

420071003_Closure_05302012_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071003/420071003_Closure_05302012_text.pdf

420071003_Final Order_11022011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071003/420071003_Final%20Order_11022011.pdf

420071003_Final Order_11022011_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071003/420071003_Final%20Order_11022011_text.pdf

420071003_Notice Letter_03272007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071003/420071003_Notice%20Letter_03272007.pdf

420071003_Operator_Response_11082007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071003/420071003_Operator_Response_11082007.pdf

Gulf South Request for Hearing.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071003/Gulf%20South%20Request%20for%20Hearing.pdf

420071003_Closure_05302012_text.pdf

CERTIFIED MAIL - RETURN RECEIPT REQUESTED
May 30, 2012
Mr. David Goodwin
Vice President, Compliance and Operations Services
Gulf South Pipeline Company, LP
9 Greenway Plaza, Suite 2800
Houston, TX 77046
CPF 4-2007-1003
Dear Mr. Goodwin:
On November 2, 2011, the Pipeline and Hazardous Materials Safety Administration (PHMSA)
issued to Gulf South Pipeline Company, LP a Final Order in the above-referenced case. This
Order included a Compliance Order and Civil Penalty assessment. Payment of the civil penalty
was received on November 17, 2011. Based on our review of the documentation you provided,
it has been determined that you have complied with the terms of this Order.
Accordingly, this case is now closed and no further action is contemplated with respect to the
matters involved in this case. Thank you for your cooperation in this matter.
Sincerely,
R. M. Seeley
Director, Southwest region
Pipeline and Hazardous
Materials Safety Administration

420071003_Notice Letter_03272007.pdf

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U.S. Deporlment
of Tronsportqlion
Plpellne ond
Hozqrdous mqterlols Soteiy
Adminlslrqiion
8701 South Gessnsr, Suite 1110
Houston, TX 77074
NOTICE OF PROBABLE VIOLATION
PROPOSED CIVIL PENALTY
and
PROPOSED GOMPLIANCE ORDER
GERTIFIED MAIL. RETURN RECEIPT REQUESTED
March 27.2007
Mr. John Earley
Senior Vice President
Gulf South Pipeline
20 E. Greenway Plaza
Suite 900
Houston, Texas 77046
cPF 4-2007-1003
Dear Mr. Earley:
During the weeks of January 23 - 27, and February 6 - 10, 2006, representatives of the
Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of
49 United States Code inspected your integrity management program in Houston, Texas.
As a result of the inspection, it appears that you have committed probable violations of the
Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and
the orobable violations are:
1. S 192.605 Procedural manual for operations, maintenance, and emergencies.
(a) General. Each operator shall prepare and follow for each pipeline, a manual of
written procedures for conducting operations and maintenance activities and for
emergency response. For transmission lines, the manual must also include
procedures for handling abnormal operations. This manual must be reviewed and
updated bythe operator at intervals not exceeding 15 months, but at least once
each calendar year. This manual must be prepared before operations of a pipeline
system commence. Appropriate parts of the manual must be kept at locations
where operations and maintenance activities are conducted.



(b) Maintenance and normal operations. The manual required by paragraph (a) of
this section must include procedures for the following, if applicable, to provide
safety during maintenance and operations.
(1) Operating, maintaining, and repairing the pipeline in accordance with
each of the requirements of this subpart and subpart M of this part.
S 192.713 Transmission lines: Permanent field repair of imperfections and
damages.
(a) Each imperfection or damage that impairs the serviceability of pipe in a steel
transmission line operating at or above 40 percent of SMYS must be -
(1) Removed by cutting out and replacing a cylindrical piece of pipe; or
(2) Repaired by a method that reliable engineering tests and analyses show
can permanently restore the serviceability of the pipe.
(b) Operating pressure must be at a safe level during repair operations.
A. On September 24 - 25, 2003, Gulf South personnel recoated a section of pipe on
their Pipeline # l-129 Agua Dulce line ai SS 123+13 which exhibited localized
corrosion pitting in the seam and in the girth weld. Gulf South did not repair the
defects either in accordance with their own O&M procedures or in accordance with a
method that reliable engineering tests and analyses shows can permanently restore
the serviceability of the pipe. Gulf South's O&M procedure, 10.8 Repair of Leaks
and Defective Pipe, requires per Table 2 - Repair Methods for Environmentally
Caused Defects, that the corrosion be repaired with a Type B Sleeve. Similarly, the
current industry standard for reliable engineering tests is the 1994 "Pipeline Repair
Manual" developed for the American Gas Association, and Table 1, "Summary of
Repair Applications", from that manual indicates that a Type B Sleeve is the only
accepted method for Factor 20 (ERW Selective Corrosion). Similarly, for Factor 27
(Girth-Weld Defect), the accepted repair applications include Grinding, Deposited
Weld Metal and Type B Sleeve.
B. On October 2-3, 2003, Gulf South personnel repaired a section of pipe on their
Pipeline # l-129 Agua Dulce line at SS 286+05 which exhibited localized and general
corrosion pitting in the seam by using a composite repair method. Gulf South did not
repair the defects in accordance with their own O&M orocedures or in accordance
with a method that reliable engineering tests and analyses shows can permanently
restore the serviceability of the pipe. Gulf South personnel repaired a section of pipe
exhibiting localized and general corrosion pitting in a longitudinal weld using a
composite sleeve by the name of PermaWrap. The current standard for reliable
engineering tests is the 1994 "Pipeline Repair Manual" developed for the American
Gas Association (A newer version has not been published to date). Table 1.
Summary of Repair Applications, from that manual indicates that a Type B Sleeve is
the only accepted method for Factor 20. ERW Selective Corrosion.



2. 5192.909 How can an operator change its integrity management program?
3.
(a) General. An operator must document any change to its program and the
reasons for the change before implementing the change.
Gulf South IMP did not have procedures and documentation requirements for
addressing changes to the lMP. Gulf South has described its overall process for
Management of Change in Section 14 of the lMP, with the process flow identified in
Figure 14.1-1. Section 14.7 indicates that modifications to the IMP follow the process in
Figure '14.1-1
. Further, changes have been made to the IMP to date, but these changes
have not been performed and documented in accordance with Gulf South's program
statements made in Figure 14.1-1 of the lMP. Gulf South did not have proper
procedures and it did not execute rule required actions even against their own process
flow descriotion.
With regard to other changes, the Gulf South IMP did not include procedures and
documentation requirements for the management of change process to address
technical, physical, procedural, and organizational changes as stated in the lMP. Gulf
South did not have any verification that they executed any management of change
activities against any elements of their program according to rule requirements.
5192.911 What are the elements of an integrity management program? An
operator's initial integrity management program begins with a framework (see
5192.907) 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 831 .8S (incorporated
by reference, see $192.7) for more detailed information on the listed element.)
(k) A management of change process as outlined in ASME/ANSI 831.8S, section
11.
The Gulf South IMP did not include a procedure to keep the BAP up-to-date with respect
to newly arising information that may require changes to the segment prioritization or
assessment method. CE's IMP Section 4.7 requires that risk assessment be updated
when new information is obtained and that the changes be evaluated to determine if
changes to the BAP are warranted but there is no procedure to ensure the process is
implemented.
IMP Section 5.'1 requires that all changes to the Baseline Assessment Plan have a
reason, be approved by the proper authority, be analyzed for implications of the changes
and be properly communicated to involved individuals but there are no detailed
procedures describing how these requirements are to be implemented, Documentation
of changes implemented since the initial baseline assessment plan developed
1211712004 has not been prepared that reflect the reason for the change, approval of the
change, analysis of the implications of the change, or the communication of the change
to stakeholders.



4. 5192.911 (see above)
(l) A quality assurance process as outlined in ASME/ANSI B31 .8S, section 12.
Gulf South did not have sufficiently comprehensive QfuQC procedures and is evidenced
by their failed QA/QC procedures for threat management as described for Index 130
below. The IMP has inadequate specification for the performance and documentation of
program reviews, both internal and external reviews, in that no definition is provided for
the scope of the proposed reviews and the periodicity expected for these reviews. The
Quality Assurance Plan for the IMP (found in Section 12.6 of the Plan) did not
adequately address the requirements of ASME 831 .8S, Chapter 12 for each element of
the lMP. There is no specification of what constitutes the set of QA/QC activities
associated with conduct of the IMP and no identification of responsibilities for those
activities. An example of inadequate QA process controls is noted in the fact that
applicable threats have not been assessed for Index 130 piping for which an lll has
been performed and credited, but no assessment has been performed to assess the
primary threat of third party damage. This threat is normally assessed by the use of
caliper pigs. This line was credited in the BAP as having been assessed, but this cannot
be complete until a caliper pig has been run. lt would be expected that the quality
assurance process would identify this discrepancy.
5.
6.
5192.911 (see above)
(l) A quality assurance process as outlined in ASME/ANSI 831 .8S, section 12,
Gulf South hired a consultant to conduct an external/independent review of the Gulf
South IMP (Review of Integrity Management Program, August 15,2005, Process
Performance lmprovement Consultants, LLC), but there is no evidence that corrective
measures recommended by this review were performed and completed and no process
exists by which to track these corrective measures to completion (e.9., as may be
evidenced by the proper use of an IMP change log). Gulf South did not have procedures
which ensure that contractors are required to have appropriate OA/AC controls. The
Tuboscope ISA did not have QA/QC specifications.
S192.911 (see above)
(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.
Gulf South did not have procedures to address how it will regularly and routinely
communicate and document IMP issues internally and how it will execute against
requests made by PHMSA and State/Local officials.
Gulf South has no formal procedures or requirements to adequately provide for regular
internal communications on a specified interval nor is an ongoing effort prescribed which



7. 8.
enables a broad internal understanding and buy-in to the lMP. The Gulf South Internal
Communications Plan simply consists of an information session provided to Field VPs,
Area Business Leaders, and the Operations group personnel during various regular staff
meetings.
Subsection 11.2.2 of the Gulf South IMP states that safety concerns raised by PHMSA
or State/local officials are to be addressed, but there are no programmatic procedures or
requirements for how this process is to be carried out and documented. IMP Section
1 1.1 references the company's Integrity Management Awareness Program. However,
this program was not made available during the inspection.
5192.915 What knowledge and training must personnel have to carry out an
integrity management program?
(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?
Gulf South did not have procedures or program qualification requirements documented
in the IMP for personnel that carry out assessments and review assessment results or
for other personnel who carry out IMP activities. Qualification requirements must be
defined for necessary lM functions - resumes or training records may then demonstrate
that qualification requirements have been met.
5192.917 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 ASME/ANSI 831.8S
(incorporated by referencet see S 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;



9.
(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.
Gulf South did not have procedures to properly evaluate and/or eliminate threats, and
Gulf South eliminated threats improperly. The basis for elimination of cyclic fatigue or
other loading conditions as a threat for all pipeline segments has not been adequately
justified in program documentation. No systematic process is described or implemented
that demonstrates how threats are evaluated for specific segments and their applicability
or non-applicability documented for use in other elements of the program.
Gulf South did not have a procedure not analyze interacting threats as required by the
regulations such as corrosion related to LF-ERW pipe or accelerated by third party or
outside force damage. Each threat has been analyzed separately, but the potential
worsening of the impact of the threats due to interaction has not been analyzed or
considered in the risk model or program documentation.
5192.917 (see above)
(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 ASME/ANSI 831 .8S, section 4. At a minimum, an
operator must gather and evaluate the set of data specified in Appendix A to
ASME/ANSI 831 .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.
Gulf South did not have procedures to gather and integrate data. No
process/procedures exist to describe the requirements to gather and/ or integrate data or
QA/QC procedures to ensure data quality.
Gulf South has not developed procedures or program controls to ensure that the data
sources listed in ASME B3'l .8S, Table 2 have been utilized forthe lMP. lf data sources
are ruled out. the basis for their exclusion must be documented. Gulf South has no
record of assumptions that have been made when missing or inadequate data has been
identified.
Gulf South has not developed procedures or program requirements to address the basis
for assumptions made when data is missing or suspect. Specifically, the following four
elements are not addressed:
r Each threat covered by the missing or suspect data is assumed to apply to the
segment being evaluated. The unavailability of identified data elements is not a
justification for exclusion of a threat.
. Conservative assumptions are used in the risk assessment for that threat and
segment or the segment is given higher priority.



10.
11.
12.
r Records are maintained that identify how unsubstantiated data are used, so that
the impact on the variability and accuracy of assessment results can be
considered.
. Depending on the importance of the data, additional inspection actions or field
data collection efforts may be required.
5192.917 (see above)
(b) Data gathering and integration. (see above)
Gulf South has not explicitly analyzed and reviewed for each covered segment the
complete data sets specified in ASME 831.8S Appendix A and summarized in Table 1
and the additional 7 data sets prescribed by the lM Rule. Where data elements have
been ruled out, the basis for their exclusion must be documented
5192.917 (see above)
(c) Risk assessment. An operator must conduct a risk assessment that follows
ASME/ANSI 831 .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 ($192.919,
192.921, 192.937), and to determine what additional preventive and mitigative
measures are needed (S192.935) for the covered segment.
Gulf South did not have orocedures to address how risk data is used to accomplish the
following objectives and it did not perform the following objectives according to rule
req uirements:
. assessing the benefits derived from mitigating action
r determining the most effective mitigation measures for the identified threats
. assessing of the integrity impact from modified inspection intervals
o assessing of the use of or need for alternative inspection methodologies
o effective resource allocation
. facilitating decisions to address risks along a pipeline or within a facility
Risk values generated by the risk model are exclusively being used to prioritize
assessments in the BAP. This adequately addresses the objective of prioritization of
segments for scheduling integrity assessments but not other requirements. IMP Section
4.1 states that the risk information is to be used to accomplish these objectives, but
there is no documentation describino how this is done.
5192.917 (see above)
(e) Actions to address particular threats. lf an operator identifies any of
the
following threats, the operator must take the following actions to address
thethreat.



13.
14.
(3) Manufacturing and construction defects. lf an operator identifies the
threat of manufacturing and construction defects (including seam defects)
in the covered segment, an operator must analyze the covered segment to
determine the risk of failure from these defects. The analysis must consider
the results of prior assessments on the covered segment. An operator may
consider manufacturing and construction related defects to be stable
defects if the operating pressure on the covered segment has not
increased over the maximum operating pressure experienced during the
five years preceding identification of the high consequence area, lf any of
the following changes occur in the covered segment, an operator must
prioritize the covered segment as a high risk segment for the baseline
assessment or a subsequent reassessment,
(i) Operating pressure increases above the maximum operating
pressure experienced during the preceding five years;
(ii) MAOP increases; or
(iii) The stresses leading to cyclic fatigue increase.
Gulf South did not have defined processes or procedures to address Manufacturing and
Construction defects. The IMP specifically did not include defined processes or
procedures describing how to monitor operating pressure increases that may occur
above the maximum operating pressure experienced during the preceding five years,
MAOP increases, or the stresses leading to cyclic fatigue increases that may have
occurred in covered segments.
5192.919 What must be in the baseline assessment plan?
An operator must include each of the following elements in its written baseline
assessment plan:
(b) The methods selected to assess the integrity of the line pipe, including an
explanation of why the assessment method was selected to address the identified
threats to each covered segment. The integrity assessment method an operator
uses must be based on the threats identified to the covered segment. (See
5192.917.) More than one method may be required to address all the threats to the
covered pipeline segment.
Gulf South did not properly assess for relevant threats or conduct the proper baseline
assessments. Gulf South pipeline Index 130 is credited with a prior lll assessment.
However, Gulf South did not have a documented process or analysis showing that all
applicable threats have been addressed by the prior assessment. The assessment did
not include a caliper run to address potential third party damage which the risk
assessment identified as a primary threat. As such, this assessment may not be credited
as a completed assessment.
5192.921 How is the baseline assessment to be conducted?
(a) Assessment methods. An operator must assess the integrity of the line pipe in
each covered segment by applying one or more of the following methods
8



15.
16,
depending on the threats to which the covered segment is susceptible. An
operator must select the method or methods best suited to address the threats
identified to the covered segment (See $192.917).
(1) Internal inspection tool or tools capable of detecting corrosion, and any
other threats to which the covered segment is susceptible. An operator
must follow ASME/ANSI 831 .8S (incorporated by reference, see 5192.7),
section 6.2 in selecting the appropriate internal inspection tools for the
covered segment.
Gulf South's IMP did not include procedures or programmatic requirements describing
the process for analysis and documentation of lLl tool selection nor did it perform the
associated rule required actions as is evidenced by lndex 130 and described in both
items 4. and 13. above. Gulf South's Evaluation and Remediation Practice #4, Inline
Inspection Practice, recognizes that lLl tools have an average of 80% accuracy
confidence, but processes do not specify the use of a tool tolerance to compensate for
potential tool and grading inaccuracies for lLl results. Gulf South did not have
procedures or programmatic requirements for quality assurance and vendor personnel
qualifications for evaluation of lLl results. There is no documented procedure or process
for recording decisional information regarding assessment methods to address identified
threats for each covered seoment.
5192.921 (see above)
(fl Newly identified areas. When an operator identifies a new high consequence
area (see 5192.905), an operator must complete the baseline assessment of the
line pipe in the newly identified high consequence area within ten (10) years from
the date the area is identified,
(g) Newly installed pipe. An operator must complete the baseline assessment of a
newly-installed segment of pipe covered by this subpart within ten (10) years from
the date the pipe is installed. An operator may conduct a pressure test in
accordance with paragraph (a)(2) of this section, to satisfy the requirement for a
baseline assessment.
Gulf South did not have procedures or programmatic requirements to complete a
baseline assessment for segment[s] having newly identified HCAs and newly installed
segments within ten [10] years from the date of identification. Procedures and process
descriptions must describe how the baseline assessment plan is updated to reflect the
reo uired assessment sched ule.
5192.933 What actions must be taken to address integrity issues?
(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 831 .8S (incorporated by
reference, see $ 192.7), section 7, Figure 4. lf an operator cannot meet the
schedule for any condition, the operator must justify the reasons why it cannot
9



17.
18.
meet the schedule and that the changed schedule will not jeopardize public
safety. An operator must notify OPS in accordance with $ 192.949 if it cannot meet
the schedule and cannot provide safety through a temporary reduction in
operating pressure or other action. An operator must also notify a State or local
pipeline safety authority when either a covered segment is located in a State
where OPS has an interstate agent agreement, or an intrastate covered segment is
regulated by that State.
Gulf South did not have procedures to implement their lM plan which does define the
process used when justifying why a remediation schedule cannot be met and why the
changed schedule will not jeopardize public safety. There is no identification of who is to
develop this justification, the contents of the justification, where the record is to be
maintained, etc. Gulf South stated that it is expected that these justifications will be
placed in dig packets, but it is also noted that there is no documented procedure or
process used for developing dig packets. Procedures for controlling both processes
need to be established to ensure repeatability.
5192.933 (see above)
(c) Schedule for evaluation and remediation. (see above)
Gulf South did not develop a prioritized schedule for remediation activities as required by
the regulations and as specified in the Gulf South IMP Section 7.5. There was no
schedule record.
5192.935 What additional preventive and mitigative measures must an operator
take to protect the high consequence area?
(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 $192.917) An operator must conduct, in accordance with
one of the risk assessment approaches in ASME/ANSI 831.8S (incorporated by
reference, see $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 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.
Gulf South did not have formal procedures or documentation to identify the required
additional P&M measures will be selected or imolemented and which also considers
both the likelihood and conseouences of a failure.
10



19. 5192.935 (see above)
(a) General requirements. (see above)
Gulf South has completed baseline assessments for several HCA segments but the
threats to those segments have not been evaluated to identify appropriate and required
P&M Measures.
20.
5192.935 (see above)
(c) Automatic shut-off valves (ASV) or Remote control valves (RGV). lf an operator
determines, based on a risk analysis, that an ASV or RCV would be an efficient
means of adding protection to a high consequence area in the event of a gas
release, an operator must install the ASV or RGV. In making that determination, an
operator must, at least, consider the following factors-swiftness of leak detection
and pipe shutdown capabilities, the type of gas being transported, operating
pressure, the rate of potential release, pipeline profile, the potential for ignition,
and location of nearest response personnel.
Gulf South did not have a documented risk analysis-based procedure to determine if
automatic shut-off valves or remote control valves should be added to their system.
21.
5192.937 What is a continual process of evaluation and assessment to maintain a
pipeline's integrity?
(b) Evaluation. An operator must conduct a periodic evaluation as frequently as
needed to assure the integrity of each covered segment. The periodic evaluation
must be based on a data integration and risk assessment of the entire pipeline as
specified in $192.917. For plastic transmission pipelines, the periodic evaluation is
based on the threat analysis specified in 5192.917(d). For all other transmission
pipelines, the evaluation must consider the past and present integrity assessment
results, data integration and risk assessment information ($192.917), and
decisions about remediation ($192.933) and additional preventive and mitigative
actions (S192.935). An operator must use the results from this evaluation to
identify the threats specific to each covered segment and the risk represented by
these threats.
Gulf South did not have procedures and documentation requirements for performing
periodic evaluations based on a data integration and risk assessment of the entire
pipeline nor did it perform the required actions per the rule requirements. The
evaluations must consider past and present assessment results, data integration, risk
assessment information, decisions about remediation, and additional preventive and
mitigative actions.
Gulf South did not have procedures and documentation requirements for performing
oeriodic evaluations to establish reassessment methods and schedules nor had it
properly established reassessment methods and schedules per rule requirements.
l1



22.
§192.937 (b) (see above).
Gulf South has not conducted periodic evaluations for those baseline assessments that
have been reported as complete per the Gulf South IMP Section 6.5.2 which specifies
that the required periodic evaluations will be conducted annually.
23.
§192.937 (see above)
(b) Evaluation. (see above)
Gulf South did not have procedures and documentation requirements for the review of
completed periodic evaluation results to determine if new information warrants changes
to reassessment intervals and/or methods.
Proposed Civil Penalty
Under 49 United States Code, § 60122, you are subject to a civil penalty not to exceed
$100,000 for each violation for each day the violation persists up to a maximum of $1,000,000
for any related series of violations. The Compliance Officer has reviewed the circumstances
and supporting documentation involved in the above probable violation(s) and ha
ecommended that you be preliminarily assessed a civil penalty of $183,000 as follows
Item number
PENALTY
1.A.
$30,000
1.B.
$30,000
4.
$16,000
10.
11.
$16,000
13.
$16,000
$16,000
14.
$16,000
17.
$16,000
22
19.
$11,000
$16,000
Proposed Compliance Order
With respect to items 1 - 23 pursuant to 49 United States Code § 60118, the Pipeline and
Hazardous Materials Safety Administration proposes to issue a Compliance Order to Gulf South
Pipeline. Please refer to the Proposed Compliance Order, which is enclosed and made a part
of this Notice.
Response to this Notice
Enclosed as part of this Notice is a document entitled Response Options for Pipeline Operators
in Compliance Proceedings. Please refer to this document and note the response options. Be
advised that all material you submit in response to this enforcement action is subject to being
made publicly available. If you believe that any portion of your responsive material qualifies for
confidential treatment under 5 U.S.C. 552(b), along with the complete original document you
must provide a second copy of the document with the portions you believe qualify for
confidential treatment redacted and an explanation of why you believe the redacted information
12



qualifies for confidential treatment under 5 U.S.C. 552(b). lf you do not respond within 30 days
of receipt of this Notice, this constitutes a waiver of your right to contest the allegations in this
Notice and authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in
this Notice without further notice to you and to issue a Final Order.
In your correspondence on this matter, please refer to CPF 4-2007-1003 and for each document
you submit, please provide a copy in electronic format whenever possible.
Sincerely,
q&,2,4,
R. M. Seeley
Director, Southwest Region
Pipeline and Hazardous
Materials Safety Administration
Enclosures: ProposedComplianceOrder
Response Options for Pipeline Operators in Compliance Proceedings
I J



PROPOSED COMPLIANCE ORDER
Pursuant to 49 United States Code S 601 18, the Pipeline and Hazardous Materials Safety
Administration (PHMSA) proposes to issue to Gulf South a Compliance Order incorporating the
following remedial requirements to ensure the compliance of Gulf South with the pipeline safety
req ulations:
1.
2.
4.
5.
6.
7.
8.
9.
10.
In regard to ltem Number 1.A of the Notice pertaining to the actions on
September 24-25,2003, where Gulf South personnel recoated a section of pipe
on their Pipeline #l-129 Agua Dulce line at SS 123+13 which exhibited localized
corrosion pitting in the seam and in the girth weld, Gulf South did not repair the
defects by following their O&M procedures or by using a method that reliable
engineering tests and analyses show can permanently restore the serviceability
of the pipe. Gulf South must excavate and make proper repairs.
In regard to ltem Number 1.B of the Notice pertaining to the actions taken on
October 2-3, 2003, where Gulf South personnel repaired a section of pipe on
their Pipeline # l-129 Agua Dulce line at SS 286+05 which exhibited localized
and general corrosion pitting in the seam, Gulf South did not repair the defects by
following their O&M procedures or by using a method that reliable engineering
tests and analyses show can permanently restore the serviceability of the pipe.
Gulf South must excavate and make proper repairs.
In regard to ltem Number 2 of the Notice pertaining to Management of Change
procedures, Gulf South must develop and implement appropriate Management of
Change procedures to cover the issues addressed.
In regard to ltem Number 3 of the Notice pertaining to BAP procedures, Gulf
South must develop and implement appropriate BAP procedures to cover the
issues addressed.
In regard to ltem Number 4 of the Notice pertaining to QfuQC procedures, Gulf
South must develop and implement appropriate QfuOC procedures to cover the
issues addressed.
ln regard to ltem Number 5 of the Notice pertaining to findings from the
external/independent review, Gulf South must detail their plans with regard to
each of the findings in the review. ln regard to ltem Number 5 of the Notice
pertaining to QAI/QC procedures for contractors, Gulf South must develop and
implement appropriate QfuQC procedures to cover the issues addressed.
In regard to ltem Numbers 6 of the Notice pertaining to internal and external
communications, Gulf South must develop and implement appropriate
Communication procedures to cover the issues addressed.
In regard to ltem Number 7 of the Notice pertaining to expected Knowledge and
Training of company personnel, Gulf South must develop and implement
appropriate Training procedures to cover the issues addressed.
In regard to ltem Numbers 8 of the Notice pertaining to Threat ldentification, Gulf
South must develop and implement appropriate Threat Assessment procedures
to cover the issues addressed.
In regard to ltem Numbers 9 of the Notice pertaining to Data Gathering and
l +



11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
2 5 .
2 4 .
Integration, Gulf South must develop and implement appropriate procedures to
cover the issues addressed.
In regard to ltem Numbers 10 of the Notice pertaining to Data Gathering and
Integration, Gulf South must develop and implement appropriate procedures to
cover the issues addressed.
In regard to ltem Number 11 of the Notice pertaining to Risk Assessment, Gulf
South must develop and implement procedures to cover the issues addressed.
In regard to ltem Number 12 of the Notice pertaining to Manufacturing and
Construction Defects, Gulf South must develop and implement procedures to
cover the issues addressed.
In regard to ltem Number 13 of the Notice pertaining to proper assessments for
prior lll assessments, Gulf South must review the discussed BAP of Index 130
and all other prior assessments and determine and document their ability to be
included as prior assessments and where necessary Gulf South must address
any shortfalls discovered during the review.
In regard to ltem Number 14 of the Notice pertaining to Assessment Methods,
Gulf South must develop and implement procedures to cover the issues
addressed.
ln regard to ltem Number 15 of the Notice pertaining to Baseline Assessments
for Newly ldentified HCA Areas, Gulf South must develop and implement
appropriate procedures to cover the issues addressed.
In regard to ltem Number 16 of the Notice pertaining to Evaluaiion and
Remediation schedules, Gulf South must develop and implement appropriate
procedures to cover the issues addressed.
In regard to ltem Number 17 of the Notice pertaining to Evaluation and
Remediation schedules, Gulf South must develop and implement appropriate
schedules to cover the issues addressed.
In regard to ltem Number 18 of the Notice pertaining to preventive and mitigative
measures, Gulf South must develop and implement appropriate procedures to
cover the issues addressed.
In regard to ltem Number 19 of the Notice pertaining to preventive and mitigative
measures, Gulf South must develop and implement appropriate evaluations to
cover the issues addressed.
In regard to ltem Number 20 of the Notice pertaining to ASVs and RCVs, Gulf
South must develop and implement appropriate procedures to cover the issues
addressed.
ln regard to ltem Numbers 21 and 22 oI the Notice pertaining to Periodic
Evaluations, Gulf South must develop and implement appropriate procedures
and evaluations to cover the issues addressed.
In regard to ltem Number 23 of the Notice pertaining to Periodic Evaluations, Gulf
South must develop and implement appropriate procedures to cover the issues
addressed.
Gulf South must address the issues detailed in ltems 1 through 23 above within
90 days after receipt of a Final Order and submit to R. M. Seeley, Director,
15



25.
Southwest Region, Pipeline and Hazardous Materials Safety Administration.
Gulf south shall maintain documentation of the safety improvement costs
issociateO with fulfilling this Compliance Order and submit the total to R' M'
S;;6y, Director, Soutliwest Region, Pipeline and Hazardous Materials Safety
Administration. costs shall be reported in two categories: 1) total cost
associated with preparation/revision oi plans, procedures, studies and analyses,
ind 2) total cosi associated with replacements, additions and other changes to
pipeline inf rastructure.
16

420071003_Final Order_11022011_text.pdf

NOV 2 2011
Mr. Michael E. McMahon
Senior Vice President and General Counsel
Gulf South Pipeline Company, LP
9 East Greenway Plaza
Suite 2800
Houston, TX 77046
Re: CPF No. 4-2007-1003
Dear Mr. McMahon:
Enclosed please find the Final Order issued in the above-referenced case. It makes findings of
violation, assesses a reduced civil penalty of $85,800, and specifies certain actions that need to
be taken by Gulf South Pipeline Company to comply with the pipeline safety regulations. The
penalty payment terms are set forth in the Final Order. When the civil penalty has been paid and
the terms of the compliance order have been completed, as determined by the Director,
Southwest Region, this enforcement action will be closed. Your receipt of the Final Order
constitutes service of that document under 49 C.F.R. § 190.5.
Thank you for your cooperation in this matter.
Sincerely,
Jeffrey D. Wiese
Associate Administrator
for Pipeline Safety
Enclosure
cc: Mr. Alan Mayberry, Deputy Associate Administrator for Field Operations, Pipeline Safety
Mr. R.M. Seeley, P.E. Director, Southwest Region, PHMSA
CERTIFIED MAIL – RETURN RECEIPT REQUESTED[71791000164202821001]



U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, D.C. 20590
___________________________________
In the Matter of )
Gulf South Pipeline Company, LP, ) CPF No. 4-2007-1003
)
)
)
Respondent. )
___________________________________ )
FINAL ORDER
During the weeks of January 23-27 and February 6-10, 2006, pursuant to 49 U.S.C.
§ 60117, representatives of the Pipeline and Hazardous Materials Safety Administration
(PHMSA), Office of Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of
the facilities and records of Gulf South Pipeline Company, LP (Gulf South or Respondent), in
Houston, Texas.
approximately 7,500 miles of pipe running from southern Texas to western Florida.
1 Gulf South operates an interstate gas pipeline system consisting of
As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to
Respondent, by letter dated March 29, 2007, a Notice of Probable Violation, Proposed Civil
Penalty, and Proposed Compliance Order (Notice). In accordance with 49 C.F.R. § 190.207, the
Notice proposed finding that Respondent had violated 49 C.F.R. §§ 192.605, 192.713, 192.909,
192.911, 192.915, 192.917, 192.919, 192.921, 192.933, 192.935, and 192.937 and proposed
assessing a civil penalty of $183,000 for the alleged violations. The Notice also proposed
ordering Respondent to take certain measures to correct the alleged violations.
Gulf South responded to the Notice by letter dated April 26, 2007 (Response), contesting all of
the allegations and requesting a hearing, which was subsequently held on October 10, 2007, in
the PHMSA Southwest Region Office, with an attorney from the Office of Chief Counsel,
PHMSA, presiding. At the hearing, Respondent was represented by counsel. On November 8,
2007, Respondent provided a summary of the evidence presented at the hearing and additional
legal arguments (Supplemental Response). As part of its Supplemental Response, Gulf South
submitted a separate response for each probable violation, with each one being entitled
“Response to Notice of Probable Violation” (Brief, Supplemental Response or Response to
Notice of Probable Violation).
1 Gulf South is a wholly-owned subsidiary of Boardwalk Partners, LP. Gulf South Pipeline Company, LP website,
available at http://www.gulfsouthpl.com/ (last accessed May 10, 2011).



2
As a general matter, in its Supplemental Response, Gulf South argued that 49 U.S.C.
§ 60109(c)(9)(A)(iii) only permits PHMSA to act under § 60109(a)(2) to order an operator to
revise its integrity management program with a Notice of Amendment type of enforcement
action (i.e., to require operators to amend their plans and procedures). Respondent further
argued that this statute precluded or did not give PHMSA the authority to act under any other
section of Chapter 601 to enforce integrity management program regulations by issuing
compliance orders and civil penalties.
With the enactment of the Pipeline Safety Improvement Act of 2002 (PSIA), the U.S. Congress
directed the Department of Transportation, PHMSA, to establish and issue regulations detailing
standards for the implementation of an integrity management program.
The authority set forth in §§ 60119 and 60122 to enforce pipeline safety standards, laws and
regulations through compliance orders and civil penalties has been codified since 1979 and
nothing in PSIA or the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006
(PIPES Act) affected this authority.
Any suggestion that, prior to the PIPES Act, § 60109(c)(9)(A)(iii) limited the agency’s authority
with respect to operator conduct and to only require an operator to amend an inadequate or
noncompliant integrity management program is therefore incorrect.
Considering the authority established in §§ 60118 and 60122; the legislative history of both
PSIA of 2002 and the PIPES Act, including H.R. Rep. No. 109-717, Part 2, § 2(g), at 16
(Dec. 5, 2006); and the legal issues presented, I find that PHMSA had the authority and did
properly exercise the full spectrum of enforcement tools upon a determination that a risk analysis
or integrity management program was inadequate or noncompliant.
FINDINGS OF VIOLATION
The Notice alleged that Respondent violated 49 C.F.R. Part 192, as follows:
Item 1: The Notice alleged that Respondent violated 49 C.F.R. §§ 192.605 and 192.713, which
state, in relevant part:
§ 192.605 Procedural manual for operations, maintenance, and
emergencies.
(a) General. Each operator shall prepare and follow for each pipeline, a
manual of written procedures for conducting operations and maintenance
activities and for emergency response. For transmission lines, the manual
must also include procedures for handling abnormal operations. This manual
must be reviewed and updated by the operator at intervals not exceeding 15
months, but at least once each calendar year. This manual must be prepared
before operations of a pipeline system commence. Appropriate parts of the
manual must be kept at locations where operations and maintenance activities
are conducted.



3
(b) Maintenance and normal operations. The manual required by
paragraph (a) of this section must include procedures for the following, if
applicable, to provide safety during maintenance and operations.
(1) Operating, maintaining, and repairing the pipeline in accordance with
each of the requirements of this subpart and subpart M of this part….
§ 192.713 Transmission lines: Permanent field repair of imperfections
and damages.
(a) Each imperfection or damage that impairs the serviceability of pipe in
a steel transmission line operating at or above 40 percent of SMYS must be—
(1) Removed by cutting out and replacing a cylindrical piece of pipe; or
(2) Repaired by a method that reliable engineering tests and analyses show
can permanently restore the serviceability of the pipe.
(b) Operating pressure must be at a safe level during repair operations.
A. Item 1A of the Notice alleged that Respondent violated 49 C.F.R. § 192.605 by failing to
follow for each pipeline the company’s own written procedures for conducting operations and
maintenance activities. Specifically, the Notice alleged that Respondent recoated a section of
pipe, on Pipeline # 1-129 Agua Dulce at SS 123+13, that exhibited localized corrosion pitting in
the seam and girth welds, in violation of Section 10.8, Repair of Leaks and Defective Pipe, of its
own Operations and Maintenance Manual (O & M Manual). PHMSA alleged that the O & M
Manual required a Type B Sleeve be used to repair selective corrosion on Factor 20 electric
resistance welded (ERW) pipe. Respondent’s dig sheet listed three metal loss areas, at a
maximum depth of .130 and a maximum length of 2 inches.
2
At the hearing and in its Supplemental Response, Gulf South gave three reasons why the cited
section of its O & M Manual was not applicable to the section of pipe in question. First,
Respondent challenged PHMSA’s characterization of the corrosion pitting as “defects” by
arguing that the pitting was an “imperfection” or “anomaly,
” not a “defect.
” To support its
argument, Respondent cited an ASME B31G strength calculation and certain other sources,
which, the company argued, indicated that the depth of the anomalies at issue did not impair the
ability of the pipeline to operate safely up to a pressure of 994 psig.3 Secondly, Respondent
cited the NACE Standard RPO 102-2002 (NACE Standard) definition of “defect,” which is “an
anomaly for which an analysis indicates that the pipe is approaching failure as the nominal hoop
stress approaches the specified minimum yield strength of the pipe material.”4
Respondent also included documentation showing that the pipe was flash-welded, not ERW, as
alleged by PHMSA. Finally, Respondent argued that because the corrosion in the seam was not
deeper than the corrosion in the adjacent body of the pipe, the corrosion on this line pipe was not
preferential and was not selective seam corrosion. Respondent cited a Kiefner and Associate’s
2 “Gulf South – Bell Hole Inspection Form,” September 24, 2003, as incorporated into the Pipeline Safety Violation
Report, March 29, 2007 (Violation Report), Exhibit A, at 3.
3 The pipeline had a maximum allowable operating pressure (MAOP) of 609.
4 NACE Standard RPO 102-2002, Section 2: Definitions.



4
letter, which supported the company’s argument by concluding that Respondent’s pipe had a
grooving ratio of less than 1 and that only grooving ratios greater than 1.4 were indicative of
selective seam corrosion.5
After considering all the evidence, I agree that Gulf South did not violate its own O & M Manual
in assessing and repairing the corrosion in question. Accordingly, I order that Item 1A be
withdrawn.
B. As in Item 1A above, Item 1B of the Notice alleged that Respondent violated 49 C.F.R.
§ 192.605 by failing to follow its manual of written procedures for conducting operations and
maintenance activities. Specifically, the Notice alleged that Gulf South improperly applied a
PermaWrap composite sleeve to SS 286+05 of Pipeline #1 -129 Agua Dulce that exhibited
localized and general corrosion pitting, in violation of its own O & M Manual, which required
repair of the corrosion with a Type B sleeve.6
At the hearing and in its Supplemental Response, Gulf South raised similar arguments as in Item
1A above to support its contention that the O & M Manual and current industry standards did not
require repair with a Type B Sleeve, normally used for the repair of “defects” that were the result
was (1) generalized or local, not “selective corrosion” in the “weld zone,” and (2) an anomaly,
not a defect.
of “selective corrosion” in the “weld zone.”7 Respondent argued that the corrosion at issue here
In support of its contention that the corrosion was generalized and not selective seam corrosion,
the company pointed to language in the Notice itself which described the corrosion as “localized
and general,
” yet alleged nevertheless that Respondent was required to use a “selective
corrosion” repair method.
Respondent pointed out that the two terms describe two distinct conditions. The company cited
an analysis by Kiefner and Associates, which found that the corrosion grooving ratio of the depth
of corrosion at the weld line to the depth of corrosion outside the weld line was less than 1.0.8
This indicated that the corrosion did not favor the weld metal to the pipe metal, and therefore
was not selective seam corrosion. PHMSA did not specify why it believed the corrosion at
SS 286+05 had to be repaired using a method appropriate for selective seam corrosion.
In support of its contention that the corrosion at issue did not amount to a defect, Gulf South
stated that the deepest penetration was less than 80%. Using the B31G strength calculation,
5 Kiefner and Associate’s April, 23, 2007 letter, “Review of Corrosion Anomalies Discovered Adjacent to the A.O.
Smith Flash Weld Seam.
”
6 PHMSA alleged that Respondent “did not repair the defects in accordance with their own O & M procedures,” but
failed to list the specific section of the O & M Manual that Gulf South allegedly violated. I assume that it was the
same section cited in Item 1A, i.e., Section 10.8, Repair of Leaks and Defective Pipe, Table 2 – Repair Methods for
Environmentally Caused Defects.
7 Section 10.8, O & M Manual, Repair of Leaks and Defective Pipe, Table 2 – Repair Methods for Environmentally
Caused Defects.
8 Kiefner & Associates, supra. Response to NOPV 1A and NOPV 1B, Table of Attachments.



5
Respondent determined a safe pressure of 694 psig and a burst pressure of 964 psig.
9
Respondent also cited the NACE Standard definition of “defect” noted above to argue that a
defect was “damage that impairs the serviceability of pipe.” Assuming the accuracy of
Respondent’s calculations and the NACE definition, the corrosion at issue here did not amount
to a defect.
PHMSA did not dispute Respondent’s calculations or the NACE definition of “defect.” Instead,
PHMSA argued that Respondent’s repair of the pipe by applying a PermaWrap sleeve indicated
that Respondent believed the anomaly did indeed “impair the serviceability of the pipe.”
Therefore, PHMSA argued that if Respondent believed a repair was needed to restore the
serviceability of the pipe, the company had to perform the repair in a manner vetted through the
development of its O & M Manual.
I disagree. Respondent’s decision to repair an anomaly does not automatically render the
anomaly a “defect” that impairs the serviceability of the pipe. If PHMSA believed that the
condition did threaten the serviceability of the pipe, it should have challenged Respondent’s
B31G strength calculation or cited some other factual support. In any event, PHMSA did not
cite any provision of the O & M Manual that Respondent allegedly violated.
As for PHMSA’s contention that Respondent failed to make repairs “that reliable engineering
tests and analyses show can permanently restore the serviceability of the pipe,” PHMSA cited
the American Gas Association’s 1994 “Pipeline Repair Manual.” Specifically, PHMSA referred
to Table 1 of that document, which directs the use of Type B sleeves for “ERW Selective
Corrosion” and “Girth weld defects.” This table, however, is not applicable to the corrosion
anomaly cited here because the anomaly was not selective seam corrosion, did not constitute a
“defect,” as defined by NACE, and was A.O. Smith line pipe, not ERW pipe.
dispute Respondent’s contention that Pipeline #1 -129 Agua Dulce was constructed of A.O.
Smith pipe.
10 PHMSA did not
Given the above facts, I am not persuaded that Section 10.8 of Respondent’s O & M Procedures,
Repair of Leaks and Defective Pipe, nor its 1994 Pipeline Repair Manual – Table 1, Summary of
Repair Applications, controls the repair of the corrosion at issue here. Therefore, I find that
Respondent was not required to apply a Type B Sleeve.
After considering all of the evidence, I find that the evidence does not support the allegation that
Respondent failed to follow its own O & M Manual in assessing and repairing the corrosion in
question. Accordingly, I order that Item 1B be withdrawn.
Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 192.909(a), which states:
§ 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.
9 The MAOP for the pipeline was 609 psig.
10 Id.



6
Item 2 of the Notice alleged that Respondent violated 49 C.F.R. § 192.909(a) by failing to
document changes to its Integrity Management Program, (IMP) before implementing such
changes. Specifically, it alleged that Gulf South’s Management of Change process (MOC Plan)
lacked procedures and documentation requirements for “technical, physical, procedural, and
organizational changes” in its IMP. In addition, the Notice alleged that Gulf South had actually
implemented certain changes in its IMP but that such changes had not been performed and
documented in accordance with the MOC Plan.
At the hearing and in its Supplemental Response, Gulf South cited its “Document History Log”
to show that substantive changes to the IMP were indeed recorded. The log showed that the IMP
was amended three times between December 1, 2004, and January 16, 2006. The three entries
were as follows:
 8-01-2005, “Reformat and overall edit. Incorporate feedback from outside consultants;”
 12-01-2005, “Edits to sections 4 and 5 per Dynamic Risk;” and
 January 16, 2006, “Revised organizational charts in section 1. Revised HCA formula
included to sections 2 and 3. Revisions to sections 4 and 5 per Dynamic risk and updated
risk data. Additional mitigative measures added to section 8.”
The Document History Log demonstrates that Respondent made certain changes to its IMP but
did not provide any real information about the substance of those changes. Gulf South provided
no information showing why the organizational charts needed revision or what actual revisions
took place. It is also impossible to tell what changes were made to the High Consequence Area,
(HCA) formula or how they might affect pipeline operations. No information was provided as to
how sections 4 and 5 of the IMP were revised or what risk information was responsible for the
changes. In short, Respondent did not “document any change to its program and the reasons for
the change before implementing the change,” as required by the regulation.
Respondent’s failure to properly document changes to its IMP also violated the terms of its own
MOC Plan. The diagram labeled “Process Flow” in the company’s MOC Plan (Section 14 of its
IMP) required the following actions to be documented and communicated prior to, during, and
following any technical, physical, procedural, or organizational change in the IMP: requesting a
change, impact of change, approval of change, plan/design change, training, implement change,
and post change assessment.
The entries in Gulf South’s Document History Log provided no substantive information about
the changes that had been made to its IMP; they did not include any of the elements in
Respondent’s MOC Process Flow. It could be argued that the first two entries cited above were
not “technical, physical, procedural, or organizational changes,” but the third entry clearly
reflected various technical, procedural, and organizational changes, including revising
organizational charts, HCA formula, and sections 4 and 5 per updated dynamic risk data. Each
of these changes should have had its own set of entries in the Document History Log. These
entries should have documented the request for each change and its anticipated impact before
final approval was given. Other entries should have included an approval of each change, how



7
the change would impact the IMP, the training required, how the change would be implemented,
and how the change actually affected the system once it was in place.11
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 192.909(a) by failing to document changes to its IMP before implementing such changes.
Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 192.911(k), which states:
§ 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 (incorporated by reference,
see § 192.7) for more detailed information on the listed element.)
(a) . . . .
(k) A management of change process as outlined in ASME/ANSI
B31.8S, section 11.
The Notice alleged that Respondent violated 49 C.F.R. § 192.911(k) by failing to have an IMP
that contained an MOC Plan with specific procedural or documentation requirements to address
changes to the IMP. PHMSA also contended that Respondent’s IMP was deficient because it did
not contain a procedure for updating the Baseline Assessment Plan (BAP) with new information
that could affect prioritization or assessment method. In support of this allegation, PHMSA cited
IMP subsections 4.7, Ongoing Reevaluation of Risk, and 5.1, Baseline Assessment Plan, alleging
that both failed to specify detailed procedures describing how those sections were to be
implemented. The two areas of alleged inadequacies with respect to the ASME Standard,
subsections 11(a) and (b), cited in the Notice will be discussed below.
As noted in Item 2 above, ASME Standard, subsection 11(a), requires that “[m]anagement of
change shall address technical, physical, procedural, and organizational changes to the
system . . . [A] documented record of changes should be developed and maintained . . . [I]t
should include the process and design information both before and after the changes were put
into place.” Respondent’s “MOC Process Flow” chart, shown in Section 14 of the MOC Plan,
uses similar wording as the list set forth in the ASME Standard, subsection 11(a). Although
Respondent’s process flow requires “documentation and communication” for each element, the
process flow and the entire MOC Plan fail to dictate who within Gulf South is responsible for
each process step. It also fails to provide any direction as to how the elements are to be
implemented, how the processes are to be documented, or by whom they should be documented.
11 As stated above, PHMSA also alleged that Gulf South’s IMP did not include procedures and documentation
requirements for the management of change process to “address technical, physical, procedural, and organizational
changes” as stated in the IMP. These issues are more appropriately dealt with under 49 C.F.R. § 192.911(k), which
was the basis for Item 3 of the Notice. Therefore, this allegation will be considered in Item 3 below.



8
Instead, it appears that the goal of MOC Plan Section 14 is simply to explain the general purpose
of an MOC Plan, rather than to communicate specific instructions on how Gulf South’s unique
MOC program is to be implemented. Without such instructions, the MOC Plan is incomplete.
Subsection 14.7, Integrity Management Program Management of Change, and Subsection 14.8,
Communications of Changes, state that “[a]ll communications of changes should be undertaken
in accordance with the requirements of Section 11, Communications Plan.” Respondent did not
attach or explain Section 11 in either its “Response to Notice of Probable Violation 2” or its
“Response to Probable Violation 3.”
Although submitted in response to PHMSA’s allegations about inadequate BAP updating
procedures and not MOC procedures, the table entitled Allocation of Responsibilities for IMP-
Related Tasks, subsection 1.2.2, assigned responsibility for various tasks in its MOC Plan,
including:
• “Review of changes to HCAs,” assigned to the Engineering/GIS Team;
• “Initiating a review (through the Management of Change process) of the adequacy of
outside force monitoring program should an unforeseen outside force event occur along a
covered segment,” assigned to Field Operations;
• “Communicating any increase in operating pressure that exceeds 10% of 5-year
historical norms, or any increase in MAOP by means of the Management of Change
processes,” assigned to Operations; and
• Three separate tasks in the “Management of Change Plan” section of the table, including,
“Reviewing, identifying, and communicating industry failure statistical trends and new
vendor information,” assigned to the IM Team and Engineering.12
The above-listed tasks show that the IMP directed that MOC procedures be utilized for certain
changes within the system but the tasks are scattered throughout the IMP task list and do not
evidence a thorough, organized process to analyze each proposed change. The Management of
Change section of the subsection 1.2.2 table does not contain tasks that correspond either to Gulf
South’s “Section 14 Management of Change Plan” or ASME Standard, subsection 11(a).
Instead, they appear to be geared towards relaying generic IMP information from industry and
PHMSA to Gulf South and vice versa. The tasks listed in this section do not “identify and
consider the impact of changes to pipeline systems,
” as required by ASME Standard, subsection
11(a).
The Notice also alleged that Respondent had no procedures to ensure that the BAP was kept
up-to-date by including new information. ASME Standard, subsection 11(b), requires that
operators recognize and respond to changed system conditions with appropriate changes to the
IMP.13
In its Response, Gulf South submitted relevant portions of its IMP to demonstrate that
12 Response to Notice of Probable Violation 3, IMP Section 1.2.2, Allocation of Responsibilities for IMP-Related
Tasks.
13 “The operator shall recognize that system changes can require changes in the integrity management program and,
conversely, results from the program can cause system changes.” ASME Standard, subsection 11(b).



9
procedures to keep the BAP up-to-date were included. Section 5 of Respondent’s IMP, which
outlines the BAP, required that “[a]ll changes to the BAP will have a reason, be approved by the
proper authority, be analyzed for implications of the change and be properly communicated to
involved individuals.” Subsection 4.7, Ongoing Reevaluation of Risk, stated: “[T]he risk
assessment will be re-calculated and the results will be reviewed to determine if changes to the
Baseline Assessment Plan are warranted.”
While these sections do not include directions as to how and by whom these goals are to be
achieved, the table at Subsection 1.2.2, Allocation of Responsibilities for IMP-Related Tasks, as
discussed above, include dozens of IMP tasks assigned to various teams. The following tasks
appear most relevant to ensuring that the BAP is kept up-to-date:
• “Review the annual risk assessment results against the BAP and revise priorities
identified in the BAP . . .,
” assigned to the IMP Team;
• “Develop and perform revisions of the IMP (prioritization of segments for assessment
and selection of assessment techniques for each segment),” assigned to the IMP Team;
• “Perform direct examination of pipe for 3rd party damage in areas where evidence of
encroachment exists,” assigned to Field Operations;
• “Refresh IRAS risk database on an annual basis and re-generate risk assessment,”
assigned to IMP Data Administration;
• “Review and validate risk assessment results,” assigned to the IMP Team;
• “Documenting and maintaining records for Risk Assessment Algorithm and BAP,”
assigned to the IMP Team; and
• “Perform assessments to determine optimal means for mitigating risk for the following
threats: third party damage, outside force (e.g., geotechnical, flooding, etc.),
manufacturing defects, welding / fabrication defects, equipment failure, and incorrect
operations,” assigned to the IMP Team and Field Operations.14
The above-listed tasks, which Respondent assigned to specific teams/departments, demonstrate
that Gulf South did have procedures in place for ensuring that changed conditions to its system
resulted in changes to the IMP. ASME Standard, subsection 11(b), provides some examples of
changes to the system that would require parallel changes to the IMP, including changes in
surrounding land use and operating pressure. Respondent did describe and assign responsibility
for various tasks to investigate these conditions and update the BAP or IMP accordingly.
Therefore, I find that Respondent had adequate procedures in place to keep its BAP updated.
After considering all the evidence, I find that Respondent violated 49 C.F.R. § 192.911(k) by
failing to have adequate MOC procedures in place to carry out its MOC Plan or ASME Standard,
subsection 11(a), as required in 49 C.F.R. § 192.911(k). However, I find that it did have
adequate procedures in place to ensure that its BAP was amended to reflect current risk
assessment data, as required in ASME Standard, subsection 11(b).
Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 192.911(l), which states:
14 IMP Section 1.2.2, “Allocation of Responsibilities for IMP-Related Tasks.” Submitted as an attachment to
“Response to Notice of Probable Violation 3.”



10
§ 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 (incorporated by reference, see § 192.7) for
more detailed information on the listed element.)
(a) . . . .
(l) A quality assurance process as outlined in ASME/ANSI B31.8S,
section 12.
The Notice alleged that Respondent violated 49 C.F.R. § 192.911(l) by failing to have an IMP
that contained a comprehensive quality assurance/quality control (QA/QC) process, as required
by ASME Standard, section 12. The allegations in the Notice generally restated the ASME
Standard, section 12, requirements. It further alleged that Respondent’s IMP did not define the
scope or frequency of QA/QC reviews. PHMSA alleged that the fact that Respondent had not
assessed threats discovered in an in-line inspection (ILI) run on Index 130 piping with a caliper
pig demonstrated the inadequacy of the IMP procedures.
Respondent contested this allegation, asserting that each subpart of ASME Standard, section 12,
was covered by its IMP. The company presented Section 12 of its IMP, Quality Control Plan
(Respondent Section 12), and argued that its plan met the requirements of ASME Standard,
section 12. A close comparison of the requirements of ASME Standard, section 12, and
Respondent’s Section 12 shows this is not the case. ASME Standard, subsection 12(b)(1),
requires that an operator “determine” and “include” the documents in its quality control plan.
Respondent’s Section 12 contains various statements about the importance of documentation in
general and that “[t]hese documents may take the form of risk assessments, reports, data
documents (e.g. collection sheets, recording charts), and this IMP Program.” A nearly identical
list appears in ASME Standard, section 12, as “examples of documented activities.” In other
words, Respondent’s IMP merely reiterated the contents of the ASME Standard, section 12, but
did not apply it to Gulf South’s own system by listing specific documents. I therefore find that
Respondent failed to create a specific list of documents.
In addition, ASME Standard, subsection 12(b)(2), also requires that “responsibilities and
authorities under this program shall be clearly and formally defined.” The Notice alleged that
Respondent’s IMP failed to identify responsibility for IMP quality-control activities.
Respondent’s IMP Section 12 states that “[t]he responsibilities and authorities required to ensure
the effective execution, application, and maintenance of this IMP Program are outlined in the
Roles and Responsibilities section of the IMP.” No such section, however, was attached to
Respondent’s “Response to Notice of Probable Violation 4.”
The next subsection of Respondent’s Section 12 states: “The Pipeline Integrity Group is
responsible for maintenance of the Company’s IMP Program.” Not only is reference to the
“Pipeline Integrity Group” vague, but Respondent’s Table 1.2.2, Allocation of Responsibilities
for IMP-Related Tasks, assigns responsibility for IMP tasks to at least six different teams or



11
authorities. No mention of the “Pipeline Integrity Group” exists in this document. I therefore
find that Respondent failed to clearly and formally define responsibilities and authorities in its
IMP.
ASME Standard, subsection 12(b)(3), further requires that “results of the integrity management
program shall be reviewed at predetermined intervals, making recommendations for
improvement.” Respondent’s Section 12 states: “Periodic review of the Program and its results
is required, as outlined in ASME/ANSI B31.8S, section 12(b)(3).” ASME Standard, section 12,
does not provide any specific interval. Respondent’s Section 12 states: “Review of the IMP
document can happen at any prescribed time . . . .” This generic statement is insufficient to
fulfill the requirement in the ASME Standard that predetermined intervals be established for
review of an operator’s IMP.
ASME Standard, subsection 12(b)(4), requires that “[t]he personnel involved in the integrity
management program shall be competent . . . . Documentation of such competence, awareness,
and qualification and the processes for their achievement, shall be part of the quality control
plan.” Respondent’s Subsection 12.5, Training and Qualification Requirements, states: “It shall
be established that a program is in place for the effective training of individuals responsible for
the effective management of the IMP. . . . They shall be trained as outlined in the Training and
Qualification Requirements section of the IMP.”
However, the Training and Qualification Requirements section of Respondent’s IMP states only
the following: (1) individuals involved in QA/QC and IMP must be, “competent, aware of the
Program and its activities, and trained to execute such activities within the Program,” (2) “it is
recommended that a number of these individuals be trained and assessed by a recognized third
party QA/QC Service Contractor,” and (3) “[a]ny such training of these individuals shall be
documented and records retained by the Operator Qualification Group.” The section is
inadequate because it simply restates the ASME requirements and contains no information about
the substance or procedures of the training process for ensuring competence, awareness, etc.
Also, ASME Standard, subsection 12(b)(4), requires that this information “shall be part of the
quality control plan.” It is not acceptable that documentation and record-keeping responsibilities
are delegated to another group instead of including the information in the quality control plan.
Therefore, I find that Respondent failed to define “the processes for their achievement” or the
documentation requirements for training.
ASME Standard, subsection 12 (b)(5), requires that “[t]he operator shall determine how to
monitor the integrity management program to show that it is being implemented according to
plan and document these steps. These control points, criteria, and/or performance metrics shall
be defined.” The Notice alleged that Respondent’s IMP had “inadequate specification for the
performance and documentation of program reviews.” Respondent’s Section 12 states:
“Performance metrics, criteria, and control points are dependent on what facet of the IMP is
being assessed. These performance measures are limitations that are set in place . . .[and] agreed
upon by Company Management in compliance with this IMP, Company Operations, Engineering
Practices, and/or Regulatory and Environmental Laws governing the industry.” Again, these
statements contain no specifics; they only describe how performance measures will be defined at
some point in the future. Therefore, I find that Respondent failed to define control points,
criteria, and/or performance metrics for monitoring implementation of its IMP.



12
ASME Standard, subsection 12(b)(6), requires that an IMP include “periodic internal audits . . .
[and] an independent third party review of the entire program.” The Notice alleged that
Respondent’s IMP lacked such a defined schedule of review. Respondent’s Section 12 required
“an annual audit of the whole program internally or concurrently with an independent third
party.” Because Gulf South’s IMP provided for annual reviews, I find that Respondent’s plan
did meet the requirements in this subsection.
ASME Standard, subsection 12(b)(7), requires that corrective actions to improve the IMP and
QA/QC program be documented and their effectiveness monitored. Respondent’s Section 12
states that “any competent and responsible employee may produce a corrective action” and that
corrective action requires a report that communicates how non-conforming actions were brought
back “within required parameters.” It further states that “Company Management” is required to
review corrective action reports. I find that this section merely restates the generic requirements
of ASME Standard, subsection 12(b)(7), and does not provide the level of detail that the ASME
Standard requires as to how corrective action will be achieved within Gulf South’s organization
under its unique operating conditions.
Finally, Respondent argued that the fact that it had not run a caliper pig was not indicative of
inadequacy in its plan. It argued that running a Magnetic Flux Leakage/hardspot ILI tool was
adequate because of its capacity to locate changes in pipeline hardness created as a result of a
deformation caused by third-party damage. As discussed in further detail in Item 14 below, the
caliper tool should have been used to locate third-party damage.
Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49
C.F.R. § 192.911(l) by failing to include an adequate quality assurance procedure in its IMP for
all but one of the seven quality-control requirements set out in ASME Standard, section 12.
Item 5: The Notice alleged that Respondent violated 49 C.F.R. § 192.911(l), as quoted above,
by failing to meet the QA/QC requirements in ASME Standard, section 12. Specifically, the
Notice alleged that Gulf South failed to take certain corrective action measures recommended by
its third-party reviewer, Process Performance Improvement Consultants, LLC (P-PIC), to
implement procedures for properly tracking corrective action measures to completion, and to
ensure that contractors had proper QA/QC controls. Under ASME Standard, subsection
12(b)(7),
“[c]orrective actions to improve the integrity management program shall be
documented and the effectiveness of their implementation monitored.”
In its Response, Gulf South included a statement from an internal P-PIC review, dated August
15, 2005, stating that Respondent had completed most of the contractor’s recommended changes.
Respondent also cited its document log, which, though lacking any detail, contained an entry
dated August 2005 to “[i]ncorporate feedback from outside consultants” and included affected
pages from its IMP reflecting the August 2005 update.
After considering all of the evidence, I find that there is insufficient evidence to support the
allegation that Respondent failed to meet the requirements of ASME Standard, section 12, as
more fully set forth above. Accordingly, this item is hereby withdrawn.



13
Item 6: The Notice alleged that Respondent violated 49 C.F.R. § 192.911(m), which states:
§ 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 (incorporated by reference, see § 192.7) for
more detailed information on the listed element.)
(a) . . . .
(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.
The Notice alleged that Respondent violated 49 C.F.R. § 192.911(m) by failing to include in its
IMP a communication plan that included the elements of ASME Standard, section 10.
Specifically, it alleged that Gulf South’s Communications Plan failed to specify how the
company documented and routinely communicated IMP issues internally and how it acted upon
requests made by PHMSA and state or local authorities. Also, it alleged that Respondent’s IMP
lacked formal communication procedures, such as specified intervals for internal
communications or requirements to ensure a broad internal understanding of the IMP.
In its Response, Gulf South argued that Section 11 of its IMP, Communications Plan, addressed
“how Gulf South regularly and routinely communicates and documents IMP issues internally and
Respondent’s Communications Plan, however, reveals that it contains only general statements
about making the IMP available to the above-listed authorities or notifying such authorities about
significant changes to the IMP. For example, Subsection 11.2.2, Communications to
Stakeholders in HCAs, states: “Communications, such as safety concerns, from OPS, state and
program or its implementation must be communicated to PHMSA within 30 days after adopting
how it responds to requests made by PHMSA and state or local officials.”15 An examination of
local pipeline authorities and other stakeholders shall be handled by the Pipeline Integrity Group
or Pipeline Safety Group, depending on the type of communications.” Furthermore, subsection
11.4, Communication of Changes, states that changes to the IMP that “substantially affect” the
the change.
Gulf South’s Response appears to acknowledge that its’ Communications Plan did not contain
specific procedures for responding to authorities’ concerns when it stated: “[N]o Gulf South-
specific safety concerns had been raised by PHMSA or state or local officials. Should safety
concerns be identified in the future, any necessary changes would be implemented in accordance
with the MOC process contained in IMP Section 14.” While this may be the case, § 192.911(m)
requires that an operator’s communications plan include procedures for addressing safety
15 Response to Notice of Probable Violation 6, at 2.



14
concerns raised by pipeline authorities. Therefore, I find that Respondent’s plan failed to include
a communications plan that included procedures for addressing safety concerns raised by OPS
and state or local authorities.
As for PHMSA’s allegation that Respondent had no formal procedures to provide for regular
internal communications, a comparison of ASME Standard, section 10, and Respondent’s plan is
necessary. The former requires that operators develop and implement an internal
communications plan that ensures integrity management personnel understand and support the
necessary changes be incorporated into the IMP, including the communications plan.
IMP.16 It also requires that performance measures be reviewed on a periodic basis and that
Gulf South’s Communications Plan, however, does not do this. On the contrary, it states:
The Integrity Management Awareness Program makes provisions for the
following communications to company employees that may be impacted by
pipeline integrity.
(1) Overview of the Integrity Management Program;
(2) Summary of Performance Measure Reviews;
(3) Results of Risk Assessment; and
(4) Identification of Changes to the IMP. . .
[C]ontrolled copies of the IMP document shall be distributed to all recipients
who are actively engaged in conducting or monitoring integrity management
activities.17
Although the Communications Plan states that the company’s Integrity Management Awareness
Program “makes provisions” for communicating IMP information to company employees, it
doesn’t provide any procedures for accomplishing this objective beyond simply ordering that
employees receive a copy of the IMP. Therefore, the statements in Respondent’s plan are merely
aspirational. In order to meet the requirements of 49 C.F.R. § 192.911(m), the IMP must provide
specific guidance or requirements as to how company personnel are expected to communicate
and document internal communications on Gulf South’s IMP. Respondent has not presented any
other evidence showing it had actually developed or implemented a specific plan to carry out
these goals.
Accordingly, after considering all the evidence, I find that Respondent violated 49 C.F.R.
§ 192.911(m) by failing to include in its IMP a communication plan that ensured internal
communications regarding IMP issues and that included procedures for addressing safety
concerns raised by PHMSA or state or local authorities.
Item 7: The Notice alleged that Respondent violated 49 C.F.R. § 192.915, which states, in
relevant part:
§ 192.915 What knowledge and training must personnel have to carry
out an integrity management program?
16 ASME Standard, subsection 10.3.
17 Section 11.3, Integrity Management Awareness Program.



15
(a) . . . .
(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.
The Notice alleged that Respondent violated 49 C.F.R. § 192.915 by failing to have procedures
or program qualification requirements documented in its IMP for personnel who carried out
assessments or evaluated assessment results. Gulf South contested this Item, asserting that
subsection 1.2.1 of its IMP described the roles and responsibilities of the personnel involved in
integrity management activities and that Section 13 of its IMP stated that the training,
qualification, and evaluation requirements for such individuals were described in its operator
qualification (OQ) document. Respondent argued that the two sections, taken together, satisfied
49 C.F.R. § 192.915(b) and (c).
Gulf South submitted copies of portions of its IMP. Section 13, Training and Qualification
Requirements, and subsection 1.2.1, Roles and Responsibilities, provide descriptions of various
personnel positions in the company (i.e., Vice President, Operations; Corrosion Manager, ILI
Manager), but do not contain either “criteria for the qualification” for these positions or a
description of how or whether these individuals are determined to be “qualified” for performance
of IMP tasks. Section 13 allows individuals to be qualified through written or oral examinations
or performance evaluations, but does not set out the criteria which must be met through such
examinations. It also states that persons conducting integrity assessments and reviewing
integrity assessments must have “proper training, knowledge and experience,” and that persons
who perform preventive and mitigative measures, “must be qualified under Company’s OQ
program.” Stating that such persons must have proper training, however, is not the same as
providing criteria against which they are to be evaluated. Respondent did not attach its OQ plan
to show the appropriate criteria for qualification. In any event, § 192.915(b) and (c) require that
the IMP contain criteria for qualification.
Accordingly, after considering all the evidence, I find that Respondent violated 49 C.F.R.
§192.915 by failing to include in its IMP the criteria for persons performing or reviewing
integrity assessments or for those performing preventive and mitigative measures.



16
Item 8: The Notice alleged that Respondent violated 49 C.F.R. § 192.917(a), which states:
§ 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
ASME/ANSI B31.8S (incorporated by reference, see § 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.
The Notice alleged that Respondent violated 49 C.F.R. § 192.917(a) by failing to identify and
evaluate in its IMP all potential threats to each covered pipeline segment, as outlined in
ASME/ANSI B31.8S, section 2. Specifically, it alleged that Gulf South failed: (1) to develop
and implement a systematic process for evaluating threats for specific pipeline segments; (2) to
adequately justify the elimination of “cyclic fatigue or other loading conditions” as a threat for
all pipeline segments; and (3) to develop a procedure for analyzing interacting threats, such as
corrosion related to low frequency ERW pipe or third-party damage.
As for the first allegation, Gulf South contended that its risk model did consider a comprehensive
list of data to assess all threats to the pipeline, including interacting threats. It cited subsection
4.4 of its IMP, Risk Assessment Methodology (§ 192.917),which outlined its own risk assessment
methodology, known as “Dynamic Risk Assessment System” (DRAS), that the company
described as a failure-likelihood algorithm or risk matrix that included 10 measures of “failure
likelihood” and three measures of “consequence.”18 According to Gulf South, the weight of each
factor was determined by “failure statistics maintained within the Company, and that were
augmented by industry statistics.”19 The procedure included a subsection on each failure threat,
which explained the detailed criteria for the scoring of that section.20
Given that the regulation does not specify how an operator must conduct the risk evaluation, we
18 The 10 failure threats, with their respective assigned weights, were: external corrosion (40%), third party damage
(15%), manufacturing defects (seam defects, hard spots) (10%), fabrication/joining (7%), old repairs (7%),
equipment failures (5%), weather and outside force (5%), internal corrosion (5%), incorrect operations (3%), and
SCC (3%). IMP Figure 4.5-1, submitted as an attachment to Response to Notice of Probable Violation 8.
19 IMP Section 4.5, Failure Likelihood Assessment, submitted as an attachment to “Response to Notice of Probable
Violation 8.”
20 For example, the external corrosion section includes a litany of factors such as pipe age, coating type, cathodic
protection, casing, soil type, failure history, etc. Depending of the type of data available for each factor, the analysis
and assumptions may vary.



17
must defer to the ASME Standard. Under subsection 5.5, “Risk Assessment Approaches,” four
different approaches are available. One of these methods, known as the “Relative Assessment
Models” approach, identifies and quantitatively weighs known threats and consequences relevant
to past pipeline operations and is consistent with the methodology used in DRAS. Accordingly,
I find no basis for the allegation that Respondent’s IMP lacked a “systematic process” for
evaluating threats on specific pipelines segments.
As for the second allegation that the company failed to adequately justify the elimination of
“cyclic fatigue or other loading conditions” as a threat for all pipeline segments, Gulf South
responded that its risk algorithm did, in fact, consider the potential for cyclic fatigue when it
calculated “defect scores for threats that are associated with seam defects and joining defects.”21
Under subsection 4.2 of its IMP, Threat Identification, it further stated that cyclic fatigue had not
occurred on Gulf South gas pipelines, but that “the Company will continue to monitor for
fatigue.” The company further noted, in subsection 4.5.6, Fabrication/Joining, that “[a]n
increase in stress conditions leading to cyclic fatigue” was included as a factor in determining
risk scores. Finally, Respondent cited a 2004 article in support of its argument that cyclic fatigue
was not a common problem in gas pipelines.22
OPS did not present any additional evidence or arguments to rebut Respondent’s defenses
against this allegation. Accordingly, I find that there is insufficient evidence to support a finding
that Gulf South failed to adequately justify the elimination of “cyclic fatigue or other loading
conditions” as a threat for all pipeline segments.
As for the third allegation that Respondent did not have a procedure for analyzing interacting
threats, Gulf South cited various sections of its IMP as evidence that it had adequate procedures
for analyzing such threats. First, it cited subsection 4.4, which states: “Because the model
considers all threats, it consequently considers multiple threats and their interaction as well.”23
Respondent is correct that the DRAS weighting and scoring system considered more than one
threat on each section of pipeline. However, the Notice alleged that Gulf South’s IMP failed to
analyze the manner by which certain threats can exacerbate others, such as corrosion and third-
party damage.24 A review of the company’s various failure threat sections reveals that the
scoring of one threat often includes consideration of another. For example, the corrosion section
included consideration of weather and environmental conditions; the SCC section included
interacting threats, as there is no mention of third-party damage in the corrosion scoring
consideration of seam weld defects.25 However, it does not appear that the model considered all
explanation or vice versa.
21 Supplemental Response, at 23.
22 “Effects of Pressure Cycles on Gas Pipelines,” Kiefner, J.F., Rosenfeld, M.J., September 17, 2004.
23 IMP Section 4.4, submitted as an attachment to “Response to Notice of Probable Violation 8.”
24 “The interactive nature of threats (i.e. more than one threat occurring on a section of pipeline at the same time)
shall also be considered. An example of such an interaction is corrosion at a location that also has third party
damage.” ASME Standard, subsection 2.2.
25 IMP Section 4, Threat Identification, Data Integration, and Risk Assessment (§ 192.917).



18
Respondent cited subsections 4.5.5 and 6.3.1 of its IMP in support of its position. However, a
review of these subsections reveals that they do not discuss how interactive threats are
considered. Both subsections contain the following simple statement: “If other interacting
threats could adversely affect the stability of residual manufacturing and construction defects, as
required by ASME B31.8S, subsection 2.2, Company will establish its assessment plans
accordingly.” It is unclear what conditions would have to exist in order for Respondent to
determine that such “interacting threats could adversely affect stability” of its covered segments.
The IMP does not provide details as to how or even when it will evaluate or make conclusions
about the presence of interacting threats. Although DRAS requires consideration of various
interacting threats, it does not meet the requirements of ASME Standard, section 2.
Accordingly, after considering all of the evidence, I find there is insufficient evidence to prove
that Respondent’s IMP lacked an adequate process for identifying and evaluating threats or that
it improperly eliminated cyclic fatigue or other loading conditions as a threat. On the other hand,
I find that Respondent did violate § 192.917(a) by failing to consider all potential interacting
threats, as required in ASME Standard, subsection 2.2.
Item 9: The Notice alleged that Respondent violated 49 C.F.R. § 192.917(b), which states:
§ 192.917 How does an operator identify potential threats to pipeline
integrity and use the threat identification in its integrity program?
(a) . . . .
(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 ASME/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.
The Notice alleged that Gulf South violated 49 C.F.R. § 192.917(b) by failing to include
proper procedures in its IMP for gathering and integrating data consistent with ASME Standard ,
section 4, which requires that design and construction data be integrated with current operational
and maintenance records. PHMSA also alleged that Respondent violated ASME Standard,
section 4, by failing to develop procedures to indicate the basis for assumptions made when data
was missing or suspect. Specifically, it alleged that Gulf South’s IMP failed to: (1) make
conservative assumptions with regard to missing threat and segment data; (2) maintain records
that identified how unsubstantiated data were used; and (3) initiate or plan actions to obtain data
where there were data deficiencies.26
In its Response, Gulf South argued that its IMP did, in fact, describe how the company gathered
26 ASME Standard, subsections 4.2.1, 4.3, and 4.4.



19
and integrated data. Respondent stated that its data owners gathered data from a number of
sources and that the company ensured data quality through certain data validation activities.
Respondent submitted Table 2, Data Source Mapping, from its IMP, listing various threats and
their information sources. However, neither this chart nor any other part of the IMP indicates
how, by whom, or what information about the listed threats is actually collected. The table
provides no information about segments or locations along Respondent’s system where the listed
threats have been detected or may be considered a threat as a result of missing data. The table
only demonstrates that information about various threats could be collected from the listed
sources.
Respondent also submitted Section 3 of its IMP, which stated that the company’s engineering
department was responsible for entering data in the GIS system. However, there was no
explanation as to how the GIS system, which contained data about activities and structures in and
around the pipeline right-of-way, gathered data about the pipeline itself. Also, IMP Section 3
stated that “PIPER records are tied to new geometry within the appropriate PODS tables and
updated in the GIS as needed.”27 whether Respondent utilized these programs to collect and integrate data.
Respondent provided no explanation, however, as to how or
The company also submitted Section 6.5.1 of its IMP, Periodic Evaluations - Data and Risk
Reviews, which states: “A re-evaluation of risk on a system-wide basis for all covered pipeline
segments shall be conducted at least once a year to ensure that the assessed threats and risk
magnitudes that are assigned to covered segments is consistent with the latest available data.”
Respondent also submitted significant portions of its IMP relating to reassessment intervals and
methods. While related to this allegation, such procedures do not explain how data is
systematically collected and integrated, which is what ASME Standard, section 4, requires.
Finally, Respondent stated that it used a system called “Data view” to align all data attributes to
assess risk, yet provided no further information about this system, either in its Response or in the
IMP sections attached to the Response. The IMP contained generalized statements about data
integration, indicating an understanding of the purpose of such a process, but included no
specific procedures as to how the company actually carried out the data integration process.28
While the analysis of the DRAS above concluded that such system was capable of adequately
assessing threats to the pipeline system, specific procedures for maintaining up-to-date
information in the DRAS are necessary to comply with ASME Standard, section 4.
ASME Standard, section 4, also requires that “[d]evelopment of a common reference system
(and consistent measurement units) will allow data elements from various sources to be
27 Nothing in Respondent’s “Response to Notice of Probable Violation 9” indicates what “PIPER” or “PODS” stand
for, assuming they are acronyms. A review of Respondent’s entire IMP Section 3 revealed that “MAOP calculations
are maintained in the Company’s PIPER database.” No explanation was located about the purpose of the “PODS”
database.
28 For example, Section 6.5. Reassessment Plan, states: “This re-evaluation shall include data integration and risk
assessment so that . . . . the impact of these changes on the risk profile of each segment, and the risk prioritization
can be accounted for.” Also, Section 6.5.4 states: “The data collected as part of the above surveys and analyses
must be maintained in the Risk Database, and any decisions and/or findings that are made as a result of the
integration and evaluation of relevant data must be documented.”



20
information provided by Respondent points to disjointed data collection and integration
procedures instead of one common, well-developed data reference system. Respondent’s
combined and accurately associated with common pipeline locations.”29 I find that the
explanation and submissions do not refute PHMSA’s allegation that the data gathering procedure
failed to meet the requirements of ASME Standard, section 4.
Finally, in response to PHMSA’s allegations that Gulf South lacked proper procedures to address
missing data and that it failed to make conservative assumptions in those instances, Respondent
cited various company policy statements indicating that conservative default scores were to be
used where data was missing. For example, Respondent cited Section 4.3.5 of its IMP, Assuring
Data Quality, where it stated that the company was “always conservative with suspect data and
defaults – worst case scenarios – are used whenever no data is available.” The Response also
provided examples of instances where conservative scores were assigned to pipe segments on
which data was unavailable. For example, the most conservative score of “10” was assigned to
two external corrosion categories where the coating type and soil type were unknown. In an
SCC category, a score of “9” was assigned where a compressor station’s distance from a point
was unknown.
While the evidence does show that Respondent made conservative assumptions with regard to
certain missing threat and segment data, there were other shortcomings in this key part of the
data integration process. Specifically, there was still no indication that Gulf South either
maintained records identifying how such unsubstantiated data were to be used or that it had
procedures in place describing how the company would initiate or plan actions (e.g., additional
inspections or field data collection efforts) to obtain data where data deficiencies existed.
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 192.917(b) by failing to have proper procedures for gathering and integrating data consistent
with ASME Standard, section 4, which requires that operators have a systematic process for
collecting and utilizing the data elements necessary for risk assessments. The missing or
inadequate procedures included processes for actually collecting threat information, for
integrating GIS and other threat data, for maintaining records identifying how unsubstantiated
data were used, and for initiating and planning actions to obtain data where data deficiencies
existed.
Item 10: The Notice alleged that Respondent violated 49 C.F.R. § 192.917(b), as quoted above,
by failing to analyze and review each covered segment of its system using the complete data sets
specified in Appendix A to the AMSE Standard, as summarized in Table 1, and the seven factors
prescribed in § 192.917(b). The Notice also alleged that certain factors of these required data
elements were excluded without explanation.
In response, Gulf South argued that the data sets listed in Appendix A to AMSE/ANSI B31.8S
and in § 192.917(b) “are applied in the Integrated Risk Assessment System (IRAS) model.”30
In
29 ASME Standard, subsection 4.5.1.
30 Supplemental Response, at 11.



21
many of the elements listed in AMSE/ANSI B31.8S and the seven factors prescribed in the rule
appear in this table. Table 4.2-1 lays out the various factors, but there is no substantive
information about the pipeline to perform an analysis. Therefore, the table does not serve to
“evaluate” the required elements needed for identifying or prioritizing threats to the pipeline. I
find nothing in the record to demonstrate that Respondent actually “gather[ed] and evaluate[d]
the set of data specified in Appendix A to ASME/ANSI B31.8S, and consider[ed] 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.”
support of this contention, Respondent submitted its Table 4.2-1.31 Respondent is correct that
Accordingly, after considering all of the evidence, I find that Respondent failed to gather and
evaluate the data as required by Appendix A of the ASME Standard and 49 C.F.R.
§ 192.917(b).
Item 11: The Notice alleged that Respondent violated 49 C.F.R. § 192.917(c), which states:
§ 192.917 How does an operator identify potential threats to pipeline
integrity and use the threat identification in its integrity program?
(a) . . . .
(c) Risk Assessment. An operator must conduct a risk assessment that
follows the 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
(§§ 192.919, 192.921, 192.937), and to determine what additional preventive
and mitigative measures are needed (§ 192.935) for the covered segment.
The Notice alleged that Respondent violated 49 C.F.R. § 192.917(c), by failing to have proper
procedures in its IMP to conduct risk assessments for identifying threats to pipeline integrity.
Specifically, it alleged that Gulf South’s risk assessment process failed to address how risk data
was used to accomplish the six specific objectives set forth in ASME Standard, subsection 5.3.32
In its Supplemental Response, Gulf South addressed each of the six ASME risk assessment
objectives. First, in response to PHMSA’s allegation that the company did not have procedures
to assess the benefits derived from mitigating actions, Gulf South contended that its use of the
“Case Study functionality of IRAS” was appropriate for determining the effect of mitigating
actions.33 However, Respondent did not provide any explanation as to what the “Case Study
31 “Table 4.2-1, Data Review and Preliminary Threat Assessment, p. IMP 4-4 to IMP 4-15, submitted as an
attachment to “Response to Notice of Probable Violation 10.”
32 ASME standard, subsection 5.3, lists the six risk assessment objectives: (a) prioritization of pipelines/segments
for scheduling assessment and mitigation; (b) assessment of the benefits derived from mitigating action; (c)
determination of the most effective mitigation measures for identified threats; (d) assessment of the integrity impact
from modified inspection intervals; (e) assessment of the use of or need for alternative inspection methodologies;
and (f) more effective resource allocation.
33 Response to Notice of Probable Violation 11, at 2.



22
functionality” of its IMP was or how it functioned, nor could PHMSA locate an explanation in
the various IMP sections that Respondent attached to its Supplemental Response. I therefore
find that Respondent’s risk assessment process did not include any means of assessing the
benefits of mitigation.
Second, in response to PHMSA’s allegation that Gulf South did not have procedures to
determine the most effective mitigation measures for identified threats, Respondent stated that
“[t]he process for determining the appropriate mitigating action is described in IMP Section 8 –
Additional Preventative Measures.”34 However, a review of Section 8 reveals that the section is
aimed at “reducing risk through mitigating the consequence of a failure . . . of various
operations-related measures, such as increased patrol frequency, increased signage, and
decreased notification response times on risk.”35 Actual pipe conditions, not “operations-related
measures,” are the focus of ASME Standard, subsection 5.3. In this context, “mitigation” refers
to “actions that can be taken to reduce or eliminate the threat to the integrity of a pipeline.”36
Thus, Section 8 of Respondent’s IMP is not responsive to the requirements in § 192.917(c).
Third, in response to PHMSA’s allegation that Gulf South did not have procedures to assess the
use of, or the need for, modified inspection intervals, Respondent stated that it could determine
the impact of modified inspection intervals by using the “Case Study functionality.” Again,
there is no explanation as to how Gulf South utilized the “Case Study functionality,” nor could
PHMSA locate such an explanation in the various IMP sections that Respondent attached to its
Supplemental Response. Gulf South also cited subsections 4.5.1, 4.5.4, and 4.5.2 of its IMP, but
these sections simply discuss how the DRAS scored various integrity threats (e.g., external
corrosion, SCC, and internal corrosion). There is minimal, if any, direct discussion of inspection
intervals and no mention of “modified inspection intervals” in these sections. Therefore, I find
that Respondent’s procedures did not assess the use of, or need for, modified inspection
intervals.
Fourth, Respondent appears to concede PHMSA’s allegation that the company lacked procedures
to address “the need for alternative inspection methodologies,” as it cited no sections of its IMP
as responsive.
Fifth, in response to PHMSA’s allegation that Gulf South’s procedures did not address effective
resource allocation, Gulf South stated that it gave assessment, mitigation, and preventive
measures priority in those areas with the highest risk scores. In support, Respondent cited
subsection 4.1 of its IMP, which states: “The Company will review annually to ensure that
adequate time and personnel have been allocated to permit effective completion of the selected
risk assessment approach.” This generic statement, however, does not set forth any procedures
or details about how this goal will be accomplished. Instead, it is merely purpose-stating.
Therefore, I find that Respondent’s procedures do not address effective resource allocation.
34 Id.
35 Response to Notice of Probable Violation 11, attachment; IMP Section 8.7. Strategies for Mitigating the
Consequences of Failure.
36 Section 7, Responses to Integrity Assessments and Mitigation.



23
Finally, Gulf South did not cite any section of its IMP in response to PHMSA’s allegation that its
procedures failed to facilitate decision-making to address pipeline and facility risks.
Accordingly, after considering all of the evidence, I find that Respondent failed to have proper
procedures in its IMP to address the above-listed risk assessment objectives in ASME Standard,
subsection 5. 5.3, as incorporated into 49 C.F.R. § 192.917(c).
Item 12: The Notice alleged that Respondent violated 49 C.F.R. § 192.917(e)(3), which states:
§ 192.917 How does an operator identify potential threats to pipeline
integrity and use the threat identification in its integrity program?
(a) . . . .
(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) . . . .
(3) Manufacturing and construction defects. If an operator identifies the
threat of manufacturing and construction defects (including seam defects) in
the covered segment, an operator must analyze the covered segment to
determine the risk of failure from these defects. The analysis must consider
the results of prior assessments on the covered segment. An operator may
consider manufacturing and construction related defects to be stable defects if
the operating pressure on the covered segment has not increased over the
maximum operating pressure experienced during the five years preceding
identification of the high consequence area. If any of the following changes
occur in the covered segment, an operator must prioritize the covered segment
as a high risk segment for the baseline assessment or a subsequent
reassessment.
(i) Operating pressure increases above the maximum operating pressure
experienced during the preceding five years;
(ii) MAOP increases; or
(iii) The stresses leading to cyclic fatigue increase.
The Notice alleged that Respondent violated 49 C.F.R. § 192.917(e)(3) by failing to have defined
procedures in its IMP for addressing manufacturing and construction defects. Specifically, it
alleged that Gulf South’s IMP failed to include procedures on how the company monitored
operating conditions, such as pressure increases above the MAOP, fluctuations, and stresses
leading to cyclic fatigue.
In its Supplemental Response, Gulf South stated that it monitored manufacturing and
construction defects through its annual risk assessment using the IRAS. In support of this
contention, Respondent submitted the following sections of its IMP:
 Subsection 4.5.5, Manufacturing Defects - provided a formula to determine the
susceptibility of a segment to hard spots, which included “operating stress level” as a
variable. It also discussed how “stress overload” was usually necessary for the growth of
seam defects.



24
 Subsection 4.5.6, Fabrication/Joining - stated that the primary joining threat along the
Gulf South system was field girth weld and dresser couplings failures and contained a
chart showing various pressure conditions to predict such situations.
 Subsection 6.3.1, Pressure Testing Plan - stated that pressure tests were appropriate to
assess pipe seam and manufacturing threats. It also stated that pressure changes or
MAOP increases would affect prioritization because such events could affect
manufacturing and construction defects.
 Subsection 8.5, Strategies for Material Defects - stated that the Operations Department
must report any operating pressure that exceeded 10% of five-year historical norms and
any increase in MAOP.
Upon review of these portions of Respondent’s IMP, I find that they did include procedures to
ensure that if manufacturing and construction defects were identified, then there was a defined
process for analyzing the affected pipe segments to determine the risk of failure from such
defects, as required under 49 C.F.R. § 192.917(e)(3). Accordingly, I order that this Item be
withdrawn.
Item 13: The Notice alleged that Respondent violated 49 C.F.R. § 192.919(b), which states:
§ 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:
(a) . . . .
(b) The methods selected to assess the integrity of the line pipe, including
an explanation of why the assessment method was selected to address the
identified threats to each covered segment. The integrity assessment method
an operator uses must be based on the threats identified to the covered
segment. (See § 192.917.) More than one method may be required to address
all the threats to the covered pipeline segment;. . . .
The Notice alleged that Respondent violated 49 C.F.R. § 192.919(b) by failing to include in its
BAP proper procedures to describe its analytical process for selecting the appropriate ILI tools or
using such information to address identified threats. In addition, it alleged that Respondent’s
BAP did not “specify the use of a tool tolerance to compensate for potential tool and grading
inaccuracies for ILI results.” Finally, it alleged that Gulf South did not have a quality assurance
procedure to ensure vendor qualification to evaluate ILI results.37
Respondent defended the adequacy of its BAP procedures against all three allegations. First, it
argued that it selected ILI tools pursuant to its IMP, Section 6, Assessment Plan, and Section 3,
Tool Selection and Management of Data of Evaluation and Remediation Practice #4, Inline
Inspection Practice, which contained detailed descriptions of many ILI tools, their usage,
37 The factual allegations in Items 13 and 14 of the Notice were erroneously reversed. The following discussion for
Items 13 and 14 therefore considers the combined allegations and the operator’s responses to both Items.



25
Section 6.1 of the company’s IMP summarized appropriate assessment methods as a function of
the threat type, including third party/mechanical damage. The “Assessment Limitations”
columns of the table stated that third-party damage may be detected through ILI Pipe Size and
Deformation Tools and that metal loss associated with third-party damage could be detected
through the use of magnetic flux leakage, (MFL) tools and possibly crack detection tools.
strengths, weaknesses, and limitations and an analysis of the ILI tool selection process.38 Also,
Second, in response to PHMSA’s allegation about the failure to specify the use of tool tolerance,
it argued that section 7.5 of its IMP, Response Schedule for Anomalous Conditions, provided that
“tool tolerance will be considered when selecting tools for remediation activities.”
Finally, Respondent argued that quality assurance was provided both through its IMP and its
contracts with vendors. Section 12.8 of its IMP, Control of Vendor-Supplied Services, stated that
all vendors must be audited and approved prior to the start of services in order to determine
whether a contractor was “qualified and accountable.” That section also required that contract
services be documented so that work could be checked to ensure compliance with the IMP.
Respondent also cited language within its vendor contracts that required vendor compliance with
API 1163 and ASNT ILI-PQ-2004.
After considering all of the evidence, I find that Gulf South’s BAP did have written procedures
for its ILI tool selection process, as required in § 192.919(b), and that it required the
consideration of tool tolerance and quality assurance of vendor personnel and work.
Accordingly, I order that Item 13 be withdrawn.
Item 14: The Notice alleged that Respondent violated 49 C.F.R. § 192.921(a), which states:
§ 192.921 How is the baseline assessment to be conducted?
(a) Assessment methods. An operator must assess the integrity of the line
pipe in each covered segment by applying one or more of the following
methods depending on the threats to which the covered segment is susceptible.
An operator must select the method or methods best suited to address the
threats identified to the covered segment (See § 192.917).
(1) Internal inspection tool or tools capable of detecting corrosion, and
any other threats to which the covered segment is susceptible. An operator
must follow ASME/ANSI B31.8S (incorporated by reference, see § 192.7),
section 6.2 in selecting the appropriate internal inspection tools for the
covered segment. . . .
The Notice alleged that Respondent violated 49 C.F.R. § 192.921(a) because its BAP failed to
select an assessment method or methods best suited to address the threats identified in particular
covered pipe segments. Specifically, it alleged that Respondent failed to use a caliper run to
address potential third-party damage, which the risk assessment had identified as a primary
threat.
In its Supplemental Response, Gulf South argued that it did not need to use a caliper tool and
38 Evaluation & Remediation Practice #4, In-Line Inspection Practice, Tool Selection and Management of Data, as
cited in “Response to Notice of Probable Violation 4” and attached as Exhibit L of the Violation Report.



26
that its combined use of a “gagging pig,” a dummy pig, and an MFL hardspot ILI tool was
sufficient because each of those tools was capable of detecting third-party damage and that the
company had integrated the results of the gagging tool with the results of the MFL tool to
conclude that no third-party damage had occurred. However, such an approach is inconsistent
with Respondent’s own IMP.
Under its own Evaluation and Remediation Practice #4 – In-Line Inspection Practice, caliper
tools are used to detect dents caused by third-party damage.39 That section also states that MFL
tools “are not reliable for detection or sizing of most defects other than metal loss.”
Furthermore, under ASME Standard, subsection 6.2, gauging and dummy tools are not
considered accurate in detecting third-party damage, especially dents that are less than 10% of
pipe diameter, and the main function of the MFL tool is to detect metal loss, not dents. The
caliper pig is the appropriate tool for the detection of dents caused by third parties.40
Respondent further argued that it had compensated for tool inaccuracies in its selection of
remediation activities and through its standard practice of performing validation digs.
Conservative selection of remediation activities and validation digs may certainly be beneficial,
but they do not alleviate Respondent’s duty to “select the method or methods best suited to
address the threats identified to the covered segment.” Therefore, Respondent’s determination
that “running a caliper pig was unnecessary because the results of the “gagging pig” together
with the MFL/hardspot tool adequately assessed third party damage” was erroneous.
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 192.921(a) by failing to select the assessment method or methods best suited to address the
threats identified on each covered pipe segment.
Item 15: The Notice alleged that Respondent violated 49 C.F.R. § 192.921(f) and (g), which
state:
§ 192.921 How is the baseline assessment to be conducted?
(a) . . . .
(f) Newly identified areas. When an operator identifies a new high
consequence area (see § 192.905), an operator must complete the baseline
assessment of the line pipe in the newly identified high consequence area
within ten (10) years from the date the area is identified.
(g) Newly installed pipe. An operator must complete the baseline
assessment of a newly-installed segment of pipe covered by this subpart
within ten (10) years from the date the pipe is installed. An operator may
conduct a pressure test in accordance with paragraph (a)(2) of this section, to
satisfy the requirement for a baseline assessment.
39 Violation Report, Item # 14.
40 ASME Standard, subsection 6.2.3, “Metal Loss and Caliper Tools for Third-Party Damage and Mechanical
Damage Threat,” states that gagging pigs are the “lowest resolution” geometry tools and that they are only
“adequate for identifying and locating severe deformation of a pipe cross section. A higher resolution is provided by
the standard caliper tools . . .” The section goes on to state that “[t]here has been limited success identifying third
party damage using magnetic flux leakage tools. MFL tools are not useful for sizing deformations.”



27
The Notice alleged that Respondent violated 49 C.F.R. § 192.921 by failing to have procedures
or programmatic requirements to complete a baseline assessment for segments having newly
identified HCAs and newly installed segments within 10 years from the date of installation or
identification.
In its Supplemental Response, Gulf South asserted that its IMP complied with the requirement
for completion of baseline assessments within 10 years for newly identified HCAs and newly
installed segments. It first cited Table 1.2.2 of its IMP, Allocation of Responsibilities for IMP
Related Task, which contained various requirements about entering new HCAs into
Respondent’s IMP. Respondent also cited its IMP Section 3.1.1, which required that “new
segments must be incorporated into the baseline plan as an HCA within one year from the date
the area is identified.” Finally, Respondent cited its IMP subsection 5.1, which stated, like
subsection 3.1.1, that new HCAs must be incorporated into the BAP within one year.
Accordingly, upon review of the materials submitted by Respondent, I find no evidence to
support the allegation that Respondent violated 49 C.F.R. § 192.921(f) and (g) as alleged in the
Notice. Therefore, I order that Item 15 be withdrawn.
Item 16: The Notice alleged that Respondent violated 49 C.F.R. § 192.933(c), which states:
§ 192.933 What actions must be taken to address integrity issues?
(a) . . . .
(c) Schedule for evaluation and remediation. An operator must complete
remediation of a condition according to a schedule prioritizing 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 (incorporated by
reference, see § 192.7), section 7, Figure 4. If an operator cannot meet the
schedule for any condition, the operator must explain the reasons why it
cannot meet the schedule and how the changed schedule will not jeopardize
public safety.
The Notice alleged that Respondent violated 49 C.F.R. § 192.933(c) for failing to have
procedures to implement an alternative remediation schedule in the event that the one provided
in ASME/ANSI B31.8S, section 7, Figure 4, could not be met. Specifically, it alleged that
Respondent’s IMP failed to identify who would be responsible for developing the justification
for an alternative schedule, where such records would be maintained, and what would be their
contents.
In its Supplemental Response, Gulf South cited subsection 7.6 of its IMP, which tracked the
requirements of the regulation and required, in the event of an inability to meet the ASME
Standard, section 7 schedule, that the company document “the reasons why the schedule cannot
be met and the basis for why the changed schedule will not jeopardize public safety.” In
response to PHMSA’s criticism that the justification procedure did not contain adequate detail,
Respondent argued that it had not had any defects on its covered segments that required
scheduled repair and therefore had no instances of failure to meet the required schedule.
Therefore, it was difficult to imagine how Respondent could describe the “contents” of a



28
justification when it had never had any defect that could potentially exceed the required
schedule.
Under § 192.933(c), an operator must remediate conditions according to either the ASME
Standard, section 7 schedule or an alternative one that has been properly justified. Gulf South
presented evidence that it did have procedures in place to address the potential need for an
alternative schedule and that it had never violated the requirement of this section to complete
such remediation in a timely manner. The regulation is written to require the operator to provide
justification for “any condition” for which the schedule cannot be met. It does not require the
operator to have a justification in place before a condition arises. PHMSA presented no evidence
or arguments to rebut the evidence provided by Respondent or to demonstrate that the company
had failed to properly remediate such conditions under § 192.933(c). Therefore, I order that Item
16 be withdrawn.
Item 17: The Notice alleged that Respondent violated 49 C.F.R. § 192.933(c), as quoted above,
by failing to develop a prioritized schedule for remediation activities, as required by the
regulations and as specified in Respondent’s IMP, subsection 7.5. In its Supplemental Response,
Gulf South argued that such a schedule was impossible to develop since it had no immediate or
scheduled anomalies in an HCA to schedule. I agree. Accordingly, based upon review of all of
the evidence, I hereby withdraw Item 17.
Item 18: The Notice alleged that Respondent violated 49 C.F.R. § 192.935(a), which states:
§ 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 § 192.917) An operator must
conduct, in accordance with one of the risk assessment approaches in
ASME/ANSI B31.8S (incorporated by reference, see § 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 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.
The Notice alleged that Respondent violated 49 C.F.R. § 192.935(a) by failing to have formal
procedures or documentation to identify the required additional preventive and mitigative (P&M)
measures.
In its Supplemental Response, Gulf South cited various sections of its IMP that it argued were
formal strategies for completing P&M measures. Respondent cited Section 8 of its IMP,



29
Additional Preventative and Mitigative Measures (§192.935), which included a flow chart for
selecting appropriate P&M measures and a narrative on various prevention measures that should
be considered to address various types of threats, including, third-party damage, outside force
damage, corrosion, material defects, and stress corrosion cracking. It also listed various
mitigative measures, including measures to reduce the consequences of failure, risk-based
optimization of mitigation measures, methods for evaluating consequence reduction, and
methods for optimizing risk reduction.
The Notice did not specify what “formal procedures” were required, either by the regulation or
by ASME Standard, section 5, nor did PHMSA produce any evidence or arguments to rebut the
evidence presented by Gulf South. Therefore, after considering all of the evidence, I find that
there is insufficient evidence to support the allegation that Respondent violated
§ 192.935(a). Accordingly, I order that Item 18 be withdrawn.
Item 19: The Notice alleged that Respondent violated 49 C.F.R. § 192.935(a), as quoted above,
by failing to evaluate several HCA segments to identify appropriate and required P&M
measures.
Respondent submitted an identical response for this Item as it did for Item 18. However, the
substance of this allegation is different than Item 18. The regulation states that “an operator
must base the additional measures on the threats the operator has identified to each pipeline
segment.” Respondent’s resubmission of its procedures in response to an allegation about
completion of the required evaluations does not refute PHMSA’s allegation. Respondent
provided no evidence to show that it had completed the evaluations of the information gathered
during the assessment of all pipeline segments that were necessary to identify appropriate P&M
measures. Accordingly, after considering all of the evidence, I find that Respondent violated 49
C.F.R. § 192.935(a) by failing to conduct evaluations for several HCA segments to identify
appropriate P&M measures.
Item 20: The Notice alleged that Respondent violated 49 C.F.R. § 192.935(c), which states:
§ 192.935 What additional preventive and mitigative measures must an
operator take?
(a) . . . .
(c) Automatic shut-off valves (ASV) or Remote control valves (RCV). If an
operator determines, based on a risk analysis, that an ASV or RCV would be
an efficient means of adding protection to a high consequence area in the
event of a gas release, an operator must install the ASV or RCV. In making
that determination, an operator must, at least, consider the following factors--
swiftness of leak detection and pipe shutdown capabilities, the type of gas
being transported, operating pressure, the rate of potential release, pipeline
profile, the potential for ignition, and location of nearest response personnel.
The Notice alleged that Respondent violated 49 C.F.R. § 192.935(c) by failing to have a
documented risk analysis procedure to determine if automatic shut-off valves or remote control
valves should be installed.



30
In its Supplemental Response, Gulf South submitted subsections 8.1, 8.2, 8.6, 8.7, and 8.8 of its
IMP to describe its approach to risk mitigation. Subsection 8.1, Additional Preventative and
Mitigative Measures (§192.935), included a table listing various P&M measures that it
considered, including installation of ASVs and RCVs. In the same section, the IMP stated that
“the following factors have been considered in prescribing prevention and mitigation measures,
when evaluating risk reduction by use of automatic shut off valves or remote control valves…”
and it set out a bulleted list of the same factors in the regulation.
Finally, in the argument portion of its Supplemental Response, Gulf South contended that its risk
mitigation methodology focused more on prevention of failures than on mitigation of failure
consequences. It cited various studies indicating that shorter valve spacing and/or rapid closing
mainline valves would not necessarily reduce injuries or fatalities, as these generally occurred at
the moment of and immediately after pressure release. Respondent did not attach copies of the
articles it had cited from the Gas Research Institute or the Pipeline Research Council
International.
After considering all of the evidence, I find that Respondent did consider the use of ASVs and
RCVs, as required by the regulation, but determined that they would not be an efficient means of
adding protection to HCAs in the event of a gas release. Accordingly, I order that this item be
withdrawn.
Item 21: The Notice alleged that Respondent violated 49 C.F.R. § 192.937(b), which states:
§ 192.937 What is a continual process of evaluation and assessment to
maintain a pipeline's integrity?
(a) . . . .
(b) Evaluation. An operator must conduct a periodic evaluation as
frequently as needed to assure the integrity of each covered segment. The
periodic evaluation must be based on a data integration and risk assessment of
the entire pipeline as specified in § 192.917. For plastic transmission
pipelines, the periodic evaluation is based on the threat analysis specified in
192.917(d). For all other transmission pipelines, the evaluation must consider
the past and present integrity assessment results, data integration and risk
assessment information (§ 192.917), and decisions about remediation
(§ 192.933) and additional preventive and mitigative actions (§ 192.935). An
operator must use the results from this evaluation to identify the threats
specific to each covered segment and the risk represented by these threats.
The Notice alleged that Respondent violated 49 C.F.R. § 192.937(b) by failing to have
procedures and documentation requirements for performing periodic evaluations based on data
IMP process for conducting periodic evaluations did not consider “past and present integrity
integration and risk assessment of its entire pipeline.41 Specifically, it alleged that Gulf South’s
assessment results, data integration, risk assessment information, decisions about remediation,
and additional preventive and mitigative actions.”
41 This Item also alleged a failure to actually perform the required evaluations. Since Item 22 includes the same
allegation, the discussion will be combined under Item 22.



31
At the hearing and in its Supplemental Response, Gulf South argued that its IMP did include
procedures for integrating data from its entire pipeline system, for refreshing the database
regularly, and for requiring that the risk assessment model be run annually. It submitted
subsections 4.7, 6.5.1, and 6.5.2 of its IMP to support its argument.
Subsection 4.7 states that the risk database will be refreshed with updated pipeline variables on
“a regular basis.” The updated pipeline variables could result from an integrity assessment or
completed mitigative or preventive actions. It provides that such information will be used to
recalculate the risk assessment, which may require changes to the BAP. Subsection 6.5.1 states
that a “re-evaluation of risk on a system-wide basis for all covered segments shall be conducted
at least once a year to ensure that the assessed threats and risk magnitudes that are assigned are
consistent with the most updated data.” It further mentions risk data, risk changes, risk
calculation, risk profile, risk analysis, risk drivers, and risk results. It states that changes in risk
may warrant a re-prioritization of the reassessment schedule.
Subsection 6.5.2 consists of a single paragraph that refers the reader to various sections of the
document specifying reassessment intervals and methodology.
While the cited sections address some of the basic elements in § 192.937(b) for the conduct of
periodic evaluations, they do not indicate that remediation actions will be considered in the risk
evaluation, as required by the regulation. Furthermore, even for the listed items, the sections do
not adequately set forth how Gulf South actually considers “past and present integrity
assessments,” how it considers decisions about remediation, or how it considers “additional
preventative and mitigative actions” to identify threats specific to each pipeline segment, nor do
any of the sections contain documentation requirements for the annual risk assessment.
Therefore, the cited sections do not comply with the regulation.
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 192.937(b) by failing to have procedures for performing periodic evaluations based upon data
integration and risk assessment of its entire pipeline.
Item 22: The Notice alleged that Respondent violated 49 C.F.R. § 192.937(b), as quoted above,
by failing to conduct periodic evaluations as frequently as needed to ensure the integrity of each
pipeline segment. Specifically, it alleged that Gulf South did not conduct the yearly evaluations
required in subsection 6.5.1 of its IMP for the baseline assessments that Respondent reported as
complete. Subsection 6.5.1, Periodic Evaluations – Data and Risk Reviews, requires a
reevaluation of risk on a system-wide basis for all covered segments, based on newly available
information. Risk prioritization and the assessment schedule must be adjusted as necessary.
In its Supplemental Response, Gulf South contended that “[i]f the annual review of risk results
and other information demonstrate the need for a different reassessment schedule, the
reassessment interval will be updated accordingly.” However, the company provided no
statement or documentation showing that it had actually conducted any annual periodic
evaluations or what the results were. Because it only cited its IMP, Gulf South’s response did
not address PHMSA’s allegation that it had failed to actually complete the required yearly
evaluations.



32
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 192.937(b) by failing to conduct or document periodic evaluations of each pipeline segment as
frequently as required by subsection 6.5.1 of its own IMP.
Item 23: The Notice alleged that Respondent violated 49 C.F.R. § 192.937(b), as quoted above,
by failing to have procedures and documentation requirements in place to use completed periodic
evaluations to determine if new information warranted any change in reassessment intervals or
methods. As stated in Item 21 above, Respondent’s procedures do not ensure the thorough
evaluation of assessment results. They also fail to include documentation requirements for the
use of evaluations that have been conducted. Documentation of such reviews is necessary to
fulfill their purpose of ensuring accurate and up-to-date risk assessments and prioritization.
After considering the evidence, I find that Respondent violated 49 C.F.R. § 192.937(b), as
quoted above, by failing to have documentation requirements for periodic evaluations.
These findings of violation will be considered prior offenses in any subsequent enforcement
action taken against Respondent.
ASSESSMENT OF PENALTY
Under 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed
$100,000 per violation for each day of the violation, up to a maximum of $1,000,000 for any
related series of violations.
In determining the amount of a civil penalty under 49 U.S.C. § 60122 and 49 C.F.R. § 190.225,
I must consider the following criteria: the nature, circumstances, and gravity of the violation,
including adverse impact on the environment; the degree of Respondent’s culpability; the history
of Respondent’s prior offenses; the Respondent’s ability to pay the penalty and any effect that
the penalty may have on its ability to continue doing business; and the good faith of Respondent
in attempting to comply with the pipeline safety regulations. In addition, I may consider the
economic benefit gained from the violation without any reduction because of subsequent
damages, and such other matters as justice may require. The Notice proposed a total civil
penalty of $183,000 for the violations cited above.
Item 4: The Notice proposed a civil penalty of $16,000 for Respondent’s violation of 49 C.F.R.
§ 192.911(l), for failing to have a comprehensive QA/QC process, as required by ASME
Standard, section 12. As discussed above, I found that Gulf South did not include an adequate
QA/QC process for all but one of the seven quality-control requirements set out in the ASME
Standard. Without proper quality assurance procedures, it is impossible to implement effectively
the enhanced protections required for HCAs and to reduce the consequences of pipeline failures
on public safety and the environment. On the other hand, the gravity of the violation is
diminished because Gulf South did meet one of the seven quality-control requirements.
Accordingly, having reviewed the record and considered the assessment criteria, including the
gravity of the violation, the culpability of Respondent, and the company’s history of prior
offenses, I hereby reduce the proposed civil penalty for violation of § 192.911(l) to $10,800.



33
Item 10: The Notice proposed a civil penalty of $16,000 for Respondent’s violation of 49
C.F.R. § 192.917(b), for failing to explicitly analyze and review each covered segment of its
system using the data sets specified in Appendix A to the AMSE Standard, as summarized in
Table 1 of ASME Standard, section 4, and the seven risk factors listed in § 192.917(b). The
Notice also alleged that certain required data elements were excluded without explanation. As
noted above, I found that while Gulf South’s IMP enumerated the various data sets and factors
required by the regulation, the company failed to actually evaluate such data to identify and
prioritize threats. Without properly identifying and analyzing the appropriate data on each
covered segment, it is possible that particular threats could go undetected, thus jeopardizing
public safety and the environment. Accordingly, having reviewed the record and considered the
assessment criteria, including the gravity of the violation, the culpability of Respondent, and the
company’s history of prior offenses, I assess Respondent a civil penalty of $16,000 for violation
of § 192.917(b).
Item 11: The Notice proposed a civil penalty of $16,000 for Respondent’s violation of 49
C.F.R. § 192.917(c), for failing to have proper procedures to conduct risk assessments for
identifying threats to pipeline integrity. Specifically, it alleged that Gulf South failed to address
how risk data were used to plan and evaluate mitigation, integrity inspection methodology, and
resource allocation according to the six risk assessment objectives in ASME Standard,
subsection 5.3. As noted above, I found that Respondent’s IMP failed to include an adequate
discussion or analysis of the six specific objectives outlined in the standard. Without properly
addressing how risk data would be used to accomplish the goals of its IMP, it is possible that the
company’s program would not accomplish the goals of the regulation, thus compromising public
safety and the environment. Accordingly, having reviewed the record and considered the
assessment criteria, including the gravity of the violation, the culpability of Respondent, and the
company’s history of prior offenses, I assess Respondent a civil penalty of $16,000 for violation
of § 192.917(c).
Item 14: The Notice proposed a civil penalty of $16,000 for Respondent’s violation of 49
C.F.R. § 192.921(a) because the company’s BAP failed to select the assessment method or
methods best suited to address the threats identified in particular covered pipe segments. The
Noticed based this allegation on the fact that Respondent had not performed a caliper run to
address potential third-party damage, which its own risk assessment had identified as a primary
threat. As noted above, I found that the company had not selected the proper assessment tools
according to its own ILI manual and as specified in ASME Standard, subsection 6.2. Gulf
South’s assessment processes fail to ensure that inspection tools are properly selected and used
thus reducing the effectiveness of its in-line inspections and jeopardize public safety and the
environment. Accordingly, having reviewed the record and considered the assessment criteria,
including the gravity of the violation, the culpability of Respondent, and the company’s history
of prior offenses, I assess Respondent a civil penalty of $16,000 for violation of
§ 192.921(a).
Item 19: The Notice proposed a civil penalty of $11,000 for Respondent’s violation of 49
C.F.R. § 192.935(a), for failing to evaluate several HCA segments to identify appropriate and
required P&M measures. As noted above, I found that Gulf South had failed to properly identify
threats to those particular segments so that appropriate P&M measures could be developed.
Without properly identifying and implementing appropriate P&M measures, Gulf South is not in



34
a position to adequately prevent failures and mitigate the consequences of potential accidents.
Accordingly, having reviewed the record and considered the assessment criteria, including the
gravity of the violation, the culpability of Respondent, and the company’s history of prior
offenses, I assess Respondent a civil penalty of $11,000 for violation of § 192.935(a).
Item 22: The Notice proposed a civil penalty of $16,000 for Respondent’s violation of 49
C.F.R. § 192.937(b), for failing to conduct baseline assessment evaluations as frequently as
needed to ensure the integrity of each pipeline segment and as required by subsection 6.5.1 of
Respondent’s IMP. As noted above, I found that Gulf South had failed to actually conduct the
required annual evaluations. Without conducting such assessment reviews, it is possible that the
company established inappropriate reassessment methods and schedules, which could adversely
affect public safety and the environment. Accordingly, having reviewed the record and
considered the assessment criteria, including the gravity of the violation, the culpability of
Respondent, and the company’s history of prior offenses, I assess Respondent a civil penalty of
$16,000 for violation of § 192.937(b).
In summary, having reviewed the record and considered the assessment criteria for each of the
Items cited above, I assess Respondent a total civil penalty of $85,800.
Payment of the civil penalty must be made within 20 days of service. Federal regulations
(49 C.F.R. § 89.21(b)(3)) require such payment to be made by wire transfer through the Federal
Reserve Communications System (Fedwire), to the account of the U.S. Treasury. Detailed
instructions are contained in the enclosure. Questions concerning wire transfers should be
directed to: Financial Operations Division (AMZ-341), Federal Aviation Administration, Mike
Monroney Aeronautical Center, P.O. Box 269039, Oklahoma City, Oklahoma 73125. The
Financial Operations Division telephone number is (405) 954-8893.
Failure to pay the $85,800 civil penalty will result in accrual of interest at the current annual rate
in accordance with 31 U.S.C. § 3717, 31 C.F.R. § 901.9 and 49 C.F.R. § 89.23. Pursuant to
those same authorities, a late penalty charge of six percent (6%) per annum will be charged if
payment is not made within 110 days of service. Furthermore, failure to pay the civil penalty
may result in referral of the matter to the Attorney General for appropriate action in a United
States District Court.
COMPLIANCE ORDER
The Notice proposed a compliance order with respect to Items 1-23 in the Notice for violations
of 49 C.F.R. §§ 192.605(a); 192.817(a); 192.909(a); 192.911(k); 192.911(l); 192.911(m);
192.915(b) and (c); 192.917(a), (b), (c), and (e); 192.919(b); 192.921(a), (f), and (g); 192.933(c);
192.935(a) and (c); and 192.937(b). I have withdrawn several of these items. The remaining
compliance order requirements are set out below.
Under 49 U.S.C. § 60118(a), each person who engages in the transportation of gas or who owns
or operates a pipeline facility is required to comply with the applicable safety standards
established under chapter 601. Pursuant to the authority of 49 U.S.C. § 60118(b) and 49 C.F.R.
§ 190.217, Respondent is ordered to take the following actions to ensure compliance with the



35
pipeline safety regulations applicable to its operations. Respondent shall:
1. With respect to the violation of § 192.909(a) (Item 2), Respondent must develop and
implement appropriate MOC procedures to cover the issues addressed.
2. With respect to the violation of § 192.911(k) (Item 3), Respondent must develop and
implement appropriate MOC procedures and documentation requirements to cover the
issues addressed.
3. With respect to the violation of § 192.911(l) (Item 4), Respondent must develop and
implement appropriate QA/QC procedures to cover the issues addressed.
4. With respect to the violation of § 192.911(m) (Item 6), Respondent must develop and
implement appropriate communication procedures to cover the issues addressed.
5 With respect to the violation of § 192.915 (Item 7), Respondent must develop and
implement appropriate training procedures to cover the issues addressed.
6. With respect to the violation of § 192.917(a) (Item 8), Respondent must develop and
implement appropriate threat assessment procedures to consider all potential interacting
threats.
7. With respect to the violation of § 192.917(b) (Item 9), Respondent must develop and
implement appropriate data gathering and integration procedures, as required under
ASME Standard, section 4.
8. With respect to the violation of § 192.917(b) (Item 10), Respondent must develop and
implement appropriate data gathering and integration procedures to cover the issues
addressed.
9. With respect to the violation of § 192.917(c) (Item 11), Respondent must develop and
implement appropriate risk assessment procedures to cover the issues addressed.
10. With respect to the violation of § 193.921(a) (Item 14), Respondent must review the
discussed BAP of Index 130 and all other prior assessments and determine and
document their ability to be included as prior assessments. Gulf South must develop and
implement procedures to cover the issues addressed.
11. With respect to the violation of § 192.935(a) (Item 19), Respondent must conduct and
implement appropriate P&M evaluations to cover the issues addressed.
12. With respect to the violation of § 192.937(b) (Item 21), Respondent must develop and
implement procedures that ensure the completion of comprehensive periodic evaluations
to cover the issues addressed.
13. With respect to the violation of § 192.937(b) (Item 22), Respondent must conduct the
periodic evaluations to cover the issues addressed.



36
14. With respect to the violation of § 192.937(b) (Item 23), Respondent must develop and
implement documentation requirements to ensure that new information gained from
periodic evaluations is utilized to determine whether reassessment intervals or methods
must be changed.
15. Gulf South must address the issues detailed in this Compliance Order within 90 days
after receipt of a Final Order and submit to R. M. Seeley, Director, Southwest Region,
Pipeline and Hazardous Materials Safety Administration.
16. Gulf South is requested to maintain documentation of the safety improvement costs
associated with fulfilling this Compliance Order and submit the total to R.M. Seeley,
Director, Southwest Region, Pipeline and Hazardous Materials Safety Administration.
Costs shall be reported in two categories: 1) total cost associated with reparation/revision
of plans, procedures, studies, and analyses, and 2) total cost associated with
replacements, additions and other changes to pipeline infrastructure.
The Director may grant an extension of time to comply with any of the required items upon a
written request timely submitted by the Respondent demonstrating good cause for an extension.
Failure to comply with this Order may result in administrative assessment of civil penalties not
to exceed $100,000 for each violation for each day the violation continues or in referral to the
Attorney General for appropriate relief in a district court of the United States.
Under 49 C.F.R. § 190.215, Respondent has a right to submit a Petition for Reconsideration of
this Final Order. The petition must be sent to: Associate Administrator, Office of Pipeline
Safety, PHMSA, 1200 New Jersey Avenue, SE, East Building, 2nd Floor, Washington, DC
20590, with a copy sent to the Office of Chief Counsel, PHMSA, at the same address. PHMSA
will accept petitions received no later than 20 days after receipt of service of this Final Order by
the Respondent, provided they contain a brief statement of the issue(s) and meet all other
requirements of 49 C.F.R. § 190.215. The filing of a petition automatically stays the payment of
any civil penalty assessed. Unless the Associate Administrator, upon request, grants a stay, all
other terms and conditions of this Final Order are effective upon service in accordance with 49
C.F.R. § 190.5.
______________________________ _______________________
Jeffrey D. Wiese Date Issued
Associate Administrator
for Pipeline Safety

## Provenance

- Official: Yes
- Source: <https://primis.phmsa.dot.gov/enforcement-data/case/420071003>
- Source ID: `phmsa-enforcement`
- SHA-256: `3d57d0d28d5ab509629841964167acb321bf0e8bec664262184449e9fcd3113a`
- Retrieved: 2026-08-20T04:44:44.458Z
- Exported: 2026-08-23T07:48:08.726Z
- Document slug: `phmsa-enforcement-420071003`

### Source metadata

```json
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  "cpf": "420071003",
  "operator": "GULF SOUTH PIPELINE COMPANY, LLC",
  "region": "Southwest",
  "pipelineType": "GAS INTERSTATE ONSHORE",
  "caseStatus": "CLOSED",
  "citedSections": [
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    "192.917(b)",
    "192.917(c)",
    "192.917(e)(3)",
    "192.919(b)",
    "192.921",
    "192.921(a)(1)",
    "192.933(c)",
    "192.935(a)",
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    "192.937(b)"
  ],
  "dataAsOf": "08/04/2026 12PM",
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}
```