# PANHANDLE EASTERN PIPELINE CO — Safety Order

**Citation:** CPF 320141008S  
**Type / status:** enforcement / historical  
**Agency:** Pipeline and Hazardous Materials Safety Administration  
**Effective:** Not stated  
**Published:** 2014-12-24

CLOSED safety order.

## Document text

Safety Order involving PANHANDLE EASTERN PIPELINE CO. The dataset does not identify a cited regulation for this case. The case was opened on 2014-12-24 and is reported as closed as of 2020-02-21. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

320141008S_Closure Letter_02212020.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320141008S/320141008S_Closure%20Letter_02212020.pdf

320141008S_Closure Letter_02212020_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320141008S/320141008S_Closure%20Letter_02212020_text.pdf

320141008S_Consent Agreement_04012015.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320141008S/320141008S_Consent%20Agreement_04012015.pdf

320141008S_Consent Agreement_04012015_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320141008S/320141008S_Consent%20Agreement_04012015_text.pdf

320141008S_Consent Order_04162015.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320141008S/320141008S_Consent%20Order_04162015.pdf

320141008S_Consent Order_04162015_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320141008S/320141008S_Consent%20Order_04162015_text.pdf

320141008S_Notice of Proposed Safety Order_12242014.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320141008S/320141008S_Notice%20of%20Proposed%20Safety%20Order_12242014.pdf

320141008S_Notice of Proposed Safety Order_12242014_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320141008S/320141008S_Notice%20of%20Proposed%20Safety%20Order_12242014_text.pdf

320141008S_Operator Response to Notice and Request for Hearing_01232015.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320141008S/320141008S_Operator%20Response%20to%20Notice%20and%20Request%20for%20Hearing_01232015.pdf

320141008S_Consent Agreement_04012015_text.pdf

U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, DC 20590
)
In the Matter of )
)
Panhandle Eastern Pipe Line Company, LP, )
a subsidiary of Energy Transfer Partners, LP, )
)
Respondent )
)
) CPF No. 3-2014-1008S
CONSENT AGREEMENT
On December 24, 2014, the Regional Director for the Central Region (the Region or Region 3)
of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline
Safety (OPS or the Agency), issued a Notice of Proposed Safety Order (Notice) to Panhandle
Eastern Pipe Line Company, LP. (PEPL or Respondent), a subsidiary of Energy Transfer
Partners, L.P. (ETP). The Notice alleged that conditions exist on PEPL’s pipeline system that
may pose a pipeline integrity risk to public safety, property, or the environment. The Notice also
proposed that PEPL take certain corrective measures to remedy the alleged conditions and ensure
that the public, property, and the environment are protected from the potential risk.
PEPL responded to the Notice by timely submitting an “Invocation of Information Consultation
and Request for Hearing,” “Statement of Issues,” and “Request for Hearing” dated January 23,
2015 (Request for Hearing). An informal consultation was held on March 18, 2015.
During the informal consultation, the PHMSA and PEPL agreed that settlement of this
proceeding will avoid further administrative proceedings or litigation of this Notice and that
entry into this Consent Agreement is the most appropriate means of resolving issues raised in the
Notice and in the public interest. Therefore, pursuant to 49 C.F.R. Part 190, without adjudication
of any issue of fact or law, and upon consent and agreement of Respondent and the PHMSA (the
Parties), the Parties agree as follows:
I. General Provisions
1. Respondent acknowledges that as the operator of PEPL, Respondent and its
pipeline system are subject to the jurisdiction of the Federal pipeline safety laws, 49 U.S.C. §
60101, et seq., and the regulations and administrative orders issued thereunder. For purposes of
this Consent Agreement, Respondent acknowledges that it received proper notice of the
PHMSA's action in this proceeding and that the Notice states claims upon which relief may be
granted pursuant to 49 U.S.C. 60101, et seq., and the regulations and orders issued thereunder.



2. Respondent agrees, for purposes of this Consent Agreement, to address the
integrity risks identified in the Notice by completing the actions specified in Section II of this
agreement (Corrective Measures) and to abide by the terms of this Consent Agreement. These
actions, including any work plans and schedules, shall automatically be incorporated into this
Consent Agreement. This Consent Agreement does not constitute a finding of violation of any
Federal law or regulation and may not be used in any civil or administrative proceeding of any
kind as evidence or proof of any fact, fault or liability, or as evidence of the violation of any law,
rule, regulation or requirement, except in a proceeding to enforce the provisions of this Consent
Agreement.
3. After Respondent returns this signed agreement, the PHMSA's representative will
present it to the Associate Administrator for Pipeline Safety recommending that the Associate
Administrator adopt the terms of this agreement by issuing an administrative order (Consent
Order) incorporating the terms of this Consent Agreement. The terms of this agreement
constitute an offer of settlement until accepted by the Associate Administrator. Once accepted,
the Associate Administrator will issue a Consent Order incorporating the terms of the agreement.
4. Respondent consents to the issuance of the Consent Order, and hereby waives any
further procedural requirements with respect to its issuance. Respondent waives all rights to
contest the adequacy of notice, or the validity of the Consent Order or this Consent Agreement,
including all rights to administrative or judicial hearings or appeals. Upon issuance of a Consent
Order for this matter, Respondent’s Request for Hearing will be deemed withdrawn.
5. This Consent Agreement shall apply to and be binding upon the PHMSA, and
upon Respondent, its officers, directors, and employees, and its successors, assigns, or other
entities or persons otherwise bound by law. Respondent agrees to provide a copy of this Consent
Agreement and any incorporated work plans and schedules to all of Respondent's officers,
employees, and agents whose duties might reasonably include compliance with this Consent
Agreement.
6. For all transfers of ownership or operating responsibility of Respondent’s PEPL
pipeline, Respondent shall provide a copy of this Consent Agreement to the prospective
transferee at least 30 days prior to such transfer and simultaneously provide written notice of the
prospective transfer to the PHMSA Region Director (Director) who issued the Notice.
7. This Consent Agreement constitutes the final, complete and exclusive agreement
and understanding between the Parties with respect to the settlement embodied in this Consent
Agreement, and resolves any claims that have been or could have been alleged regarding the
May 5, 2009 Line 200 incident near Rockville, Indiana (including PHMSA CPF 3-2009-1009H),
items found during the Kansas and Missouri inspection conducted from June 18, 2012 to July
2012 involving 49 CFR Part 192, Subpart I – Requirements for Corrosion Control, the November
28, 2013 Line 400 incident near Houstonia, Missouri and the October 13, 2014 Line 100 incident
near Centerview, Missouri. The Parties acknowledge that there are no representations,
agreements or understandings relating to the settlement other than those expressly contained in
this Consent Agreement, except that the terms of this Consent Agreement may be construed by
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reference to the Notice. CPF 3-2009-1009H will be closed once PEPL submits its Final Report to
the Director.
8. Nothing in this Consent Agreement affects or relieves Respondent of its
responsibility to comply with all applicable requirements of the Federal pipeline safety laws, 49
U.S.C. § 60101, et seq., and the regulations and orders issued thereunder. Nothing in this
Consent Agreement alters the PHMSA's right of access, entry, inspection, and information
gathering or the PHMSA's authority to bring enforcement actions against Respondent pursuant to
the Federal pipeline safety laws, the regulations and orders issued thereunder, or any other
provision of Federal or State law.
9. This Consent Agreement does not waive or modify any Federal, State, or local
laws or regulations that are applicable to Respondent's pipeline systems. This Consent
Agreement is not a permit, or a modification of any permit, under any Federal, State, or local
laws or regulations. Respondent remains responsible for achieving and maintaining compliance
with all applicable Federal, State, and local laws, regulations and permits.
10. This Consent Agreement does not create rights in, or grant any cause of action to,
any third party not party to this Consent Agreement. The U.S. Department of Transportation is
not liable for any injuries or damages to persons or property arising from acts or omissions of
Respondent or its officers, employees, or agents carrying out the work required by this Consent
Agreement. Respondent agrees to hold harmless the U.S. Department of Transportation, its
officers, employees, agents, and representatives from any and all causes of action arising from
any acts or omissions of Respondent or its contractors in carrying out any work required by this
Consent Agreement.
II. Corrective Measures
11. Measures set forth below.
Upon issuance of the Consent Order, Respondent agrees to perform the Corrective
12. complete the following:
Regarding the 100 Line failure occurring on October 13, 2014, PEPL shall
(A) (B) Within 90 days of the Effective Date of this Order, PEPL shall complete a
root cause failure analysis (RCFA) for the 100 Line failure occurring on
October 13, 2014, and submit a final report for this RCFA to the Director.
The RCFA shall include the results of the mechanical coupling testing
being conducted at Stress Engineering and prior coupling failures.
Recommended actions to address the contributing factors shall be included
in the report as long as it is not inconsistent with 49 CFR Part 192 or
industry best practices and discussed with the Director to develop an
appropriate implementation schedule.
Within 45 days of the Effective Date of this Order, complete mechanical
and metallurgical testing and failure analysis of the failed pipe, including
an analysis of soil samples and any foreign materials. Ensure that the
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(C) (D) testing laboratory provides any report, whether draft or final, in its entirety
to the Director at the same time it is presented to PEPL.
The pipeline segment from mainline valve (MLV) 105 to MLV 106 gate is
currently limited to operation at a pressure not to exceed 75 psig. In the
event that PEPL requires operation of that segment above 75 psig, PEPL
will provide to the PHMSA a plan for the Director’s approval prior to
resuming operations at higher pressures. As appropriate based on the final
identified RCFA contributing factors, the plan shall include the following:
i. Instrumented leak survey between MLVs 105 and 106 to include
associated farm taps or temporary school line replacements. Any
leaks found must be remediated before continuing on with the
restart plan.
ii. Specify a daylight pressure increase and include advance
notification with the local emergency response officials.
iii. Reinforcing or removing 100 Line couplings located on the
property associated with the failure or the adjacent road crossing
and exhibiting characteristics or under influences identified by the
RCFA.
Within 1 year after the Effective Date of this Order, PEPL will develop a
Coupling Remedial Work Plan (Coupling RWP) which is intended to
address integrity issues on pipeline segments exhibiting the similar
properties, characteristics or outside force influences as those determined
to be causal to the 100 line failure or other coupling failures. The
Coupling RWP shall be submitted to the Director for approval. Elements
of the Coupling RWP will include:
i. Reinforce or remove 200 Line couplings on the property or the
adjacent road crossing associated with the failure that exhibit
characteristics or are under influences identified by the RCFA.
Completion dates for this activity will be proposed in the Coupling
RWP and approved by the PHMSA.
ii. Reinforce or remove couplings on the 100 and 200 Lines located in
an HCA or within the calculated potential impact radius (PIR) that
contains one or more structures intended for human occupancy that
exhibit characteristics or are under influences identified by the
RCFA. Where warranted, the reinforcement or removal of the
couplings located in these areas shall be completed within no more
than 5 years from the Effective Date of this Order.
iii. Conduct aerial instrumented (LIDAR) survey annually on lines
100 and 200 until items i. and ii. are complete and provide a
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priority based response/repair schedule for all leaks utilizing the
following categories:
a. Leaks identified as an imminent public safety threat as
defined through joint agreement by the PHMSA and PEPL;
b. Leak indications located in an high consequence area
(HCA) or Class 3 area;
c. Leak indications located within a PIR that contains a
structure intended for human occupancy or a location
intended of an outdoor area of assembly;
d. Leak indications located within the right-or-way of an
active street, highway, road or railroad;
e. Leak indications located in an area where the pipeline
operates above 72% SMYS.
iv. Utilize information gained from the above activities to further
enhance or refine criteria or characteristics that lead to a response.
Data to be collected and integrated will include ILI data and as-
found condition of and environmental conditions (depth of cover,
soil stability, compaction, buoyancy factors, coupling engagement,
leakage, etc.) associated with couplings targeted for reinforcement
and couplings discovered to be leaking through surveys or patrols.
v. Consideration of operating pressure reductions if practical to
mitigate the occurrence or consequences of coupling failures for
the 100 and 200 lines.
13. Regarding the Houstonia 400 Line failure occurring on November 28, 2013,
PEPL shall complete the following:
(A) Within 45 days after the Effective Date of this Order, PEPL shall work
with the PHMSA to finalize the Houstonia 400 line RCFA reports
(internal and Blacksmith Group) and have been previously submitted to
the PHMSA Central Region. Once finalized, PEPL shall provide for the
Director’s review and approval an implementation plan and schedule
addressing each finding and recommendation identified in the RCFA
reports. Any finding or recommendation that would exceed one year for
implementation will be identified and reviewed for concurrence by the
Director. Integrate the findings of the RCFA into other data integration
efforts and work plan efforts.
(B) Within 90 days after the Effective Date of this Order, PEPL will develop a
Corrosion Remedial Work Plan (Corrosion RWP) which is intended to
address integrity issues on pipeline segments exhibiting similar properties,
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characteristics or influences as those determined to be causal to the
Houstonia 400 line failure. The Corrosion RWP shall be submitted to the
Director for approval. Elements of the Corrosion RWP will include:
i. Integration of causal factors identified in the RCFA and applied to
similar pipeline segments;
ii. Inline inspection (ILI) tool re-grade to improve accuracy as
necessary;
iii. Engineering assessment of low potential areas coincident with
identified external corrosion metal loss;
iv. Engineering assessment of similar external corrosion morphology;
v. Identify required anomaly response, respond to and repair/replace
as necessary;
vi. Identify, prioritize and mitigate cathodic protection (CP) system
deficiencies;
vii. Re-run ILI technology if necessary and respond accordingly;
(C) Within 1 year of the Effective Date of this Order, conduct an aerial
instrumented (LIDAR) survey on lines 300 and 400 and provide a priority
based response/repair schedule for all leaks utilizing the following
categories:
i. Leaks identified as an imminent public safety threat as defined
through joint agreement by the PHMSA and PEPL;
ii. Leak indications located in an high consequence area (HCA) or
Class 3 area;
iii. Leak indications located within a PIR that contains a structure
intended for human occupancy or a location intended of an outdoor
area of assembly;
iv. Leak indications located within the right-or-way of an active street,
highway, road or railroad;
v. Leak indications located in an area where the pipeline operates
above 72% SMYS.
14. Develop a Process Improvement Remedial Work Plan (Process Improvement
RWP) to systemically improve the integrity management and corrosion control programs for the
PEPL system. Within 1 year of the Effective Date of this Order, PEPL must submit, for review
and approval to the PHMSA, a comprehensive written Process Improvement RWP, including
6



timelines for specific actions of development, process review and implementation. Respondent
must address deficiencies, threats or risks, and necessary improvements identified in the RCFAs
and/or as required under Part 192. As necessary, this may include process improvements,
integrity assessments, repair and/or replacement of pipeline assets and other measures. The plan
will be designed to improve four strategic areas of the PEPL system performance and must be
sufficiently detailed with specific tasks, milestones, completion dates and reporting summaries.
The Process Improvement RWP shall be submitted to the Director for approval:
(A) Consultation with Independent Third-Party
i. ii. Respondent will engage a third party consultant (Consultant)
acceptable to the PHMSA. PEPL will submit vendor names/
credentials for consideration by the PHMSA and the PHMSA will
approve the list from which Respondent will select one or more
consultants to perform this service. As part of its review, PHMSA
may request additional information and/or assurances to support
the independent nature of the Consultant(s)’s work product. The
selected Consultant(s) will be utilized to supplement PEPL’s in-
house functional/technical personnel in a review of PEPL current
and proposed processes/procedures/protocols to identify
improvements where applicable in each of the topical areas of the
Process Improvement RWP. To this end, specific expertise may be
brought to bear within these topical areas and will require an
individual or individuals with appropriate expertise to provide the
consultancy needed.
In general, the scope of the engagement will involve the
Consultant(s) providing these services/input into the development
process for the Process Improvement RWP including:
a. Review relevant information/procedures/programs related to
the topical area including metallurgical and RCFA reports for
historical and relevant incidents (external corrosion and
mechanical couplings), integrity management program
documents and procedures, safety program elements and
management systems.
b. Conduct interviews with in-house functional/technical
personnel as needed to gain understanding of current state,
improved future state and proposed path to close existing gaps.
c. Review current actions and procedural changes being
contemplated or initiated and compare to the knowledge base
of the Consultant and recommend incremental improvements
as warranted.
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(B) i. d. Prepare status reports relative to findings, conclusions,
recommendations and incorporation of agreed upon
improvements into the Process Improvement RWP and
resultant deliverables. The Consultant must provide all reports
to both PEPL and the PHMSA concurrently.
e. PEPL will provide the PHMSA with written proposed
resolutions for all of the Consultant’s recommendations.
iii. The Consultant(s) will report directly to an Energy Transfer/PEPL
leadership team (Vice-President or above). The Consultant’s
engagement with PEPL will conclude upon approval of the Process
Improvement RWP by the PHMSA.
The four strategic areas with specific targeted improvement opportunities
are detailed as follows:
Improve Corrosion Control and Prevention Program
a. Implement the polarized potential (instant off) criteria on the
PEPL system and address identified low potential areas in
accordance with PEPL standard operating procedures (D.40);
b. Modify the procedures regarding CP ground bed analysis and
replacement to include provisions for testing the adequacy of
negative connections in order to provide and monitor levels of
CP to all parallel pipelines;
c. Improve the methodology, tracking and completion of
prioritized activities related to the remediation of CP
deficiencies;
d. Develop a management system to track and report on
deficiencies discovered and action items completed;
e. Modify procedures to require mitigation of CP deficiencies in a
specified time frame that is within the regulatory framework of
the inspection frequency;
f. Add additional CP current density to account for/mitigate the
potential Microbiologically Induced Corrosion (MIC) effect on
corrosion growth rates where applicable;
g. Provide training to field technicians on proper analysis of
current distribution, rectifier placement, and negative cable
connections;
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ii. h. Require corrosion technicians and corrosion specialists to
complete comprehensive CP data analysis;
i. Evaluate the current status of the Company’s corrosion control
procedures, especially those relating to close interval survey
(CIS) execution and response, data integration of ILI and CIS
and training to identify if any deficiencies need to be
addressed;
j. Review and revision as appropriate, standard operating
procedures (SOPs) guiding the pipe inspection process to look
and/or test for environmental factors including MIC and
consideration of it as a contributor to corrosion growth rates;
k. Evaluate the corrosion growth rate process to determine what if
any enhancements can be made;
l. Review and improve management practices related to the
setting of priorities for corrosion technicians and the
management and resource support of their workload;
m. Review and improve processes and criteria associated with the
testing of electrical isolation for cased crossings;
n. Review and improve processes to identify electrical high
resistance couplings and remediate (bond across coupling) such
couplings to the extent remediation is required to restore
adequate cathodic protection to the pipeline;
o. Review and identify that processes and procedures clearly
define the term “critical bond.” Provide monitoring criteria for
all bonds;
p. Ensure processes and procedures associated with CIS identify
maximum potentials and ensure that adequate follow-up
associated with potential interference is implemented.
Improve Integrity Management Processes for External Corrosion
and Mechanical Coupling Threats
a. Enhance the ILI data validation process with the appropriate
use and analysis of pseudo digs and excavation of anomalies
and incorporate CP performance data and ILI run to run
calculations in the validation process. A process to define
appropriate pseudo dig use will be developed;
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iii. b. Enhance procedures to verify ILI data is aligned properly and
calculations are accurate;
c. Enhance the process and procedures for data integration;
overlay CIS and ILI data with GIS and topographical mapping
features;
d. Modify and implement the ILI tool specification to require ILI
service providers to report the amount of manual grading, the
associated parameters, and any changes as a result of the
manual analysis for each ILI run;
e. Expand the annual ILI pre-bid meeting beyond the current
specification review of changes to include verification of key
integrity concepts such as interaction and data validation and
ILI vendor analyst staffing;
f. Develop and employ a quality control (QC) process to further
improve the accuracy of field measurements of corrosion
anomalies. Utilize a benchmark measurement system with a
high degree of accuracy to which field measurements can be
compared;
g. Develop and employ an ILI specification, depth of cover, soil
stability and data integration process to enable ongoing
integrity assessments for mechanical couplings;
h. Develop a grading and prioritization scheme to assess and
appropriately schedule responses to mechanical coupling
threats outside of HCAs and absent structures and outside areas
within the PIR of a line containing a mechanical coupling;
i. Review the internal processes for pressure reductions and/or
submission of a Safety Related Condition Report.
Enhanced Safety and Integrity Management Culture through
Reporting, Learning and Training
a. Expand/enhance the existing ETP Safety Culture program and
processes with emphasis on pipeline integrity and corrosion
control. Apply the existing processes within the Impact Safety
Management System to identify, report and manage unwanted
events. Utilize the existing system that encourages continuous
improvement and a learning culture. Develop specific
elements and process requirements related to pipeline integrity
including:
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1. Reporting criteria for additional unwanted events and
issues;
2. Action item and learning process workflow;
3. Management of change process workflow;
4. Development of Key Performance Indicators (KPIs)
indicative of corrosion control and pipeline integrity
process performance.
b. In consideration of process and procedure improvements
resulting from the recent ETP incident history and RCFAs,
proactively manage the subject improvements and assure a
formal MOC process occurs. Develop and provide required
training and communication programs to assure people, process
and technology elements are fully implemented across the
enterprise and changes are institutionalized accordingly
including:
1. Update of SOPs and integrity management program
documents;
2. Training field technicians and subject matter experts
(SMEs) in Corrosion Control and Integrity Management
procedural/program changes;
3. Provide training and communication to technical support
and management personnel related to changes in work
management and management of KPIs;
4. Provide ongoing attention to outside influences including
organizational changes, mergers, acquisitions, resource
changes, retirements, new hires, etc. and assure that such
changes are managed such that safety performance is not
negatively impacted.
c. Provide quarterly process improvement updates to the PHMSA
including status of related changes and KPIs.
iv. Management System/Data Integration
PEPL shall prepare a strategic data system improvement plan that
will allow the effective collection, review, integration and analysis
of integrity related data. The plan will define how PEPL will
perform timely analysis of integrity related data, recognize
integrity threats, identify effective mitigative and preventative
measures, and support effective decision making. This data system
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strategic plan shall be completed within 1 year from the Effective
Date of this Order. This shall be submitted to the Central Region
Director for review and comment. An implementation schedule
shall be submitted to the Central Region Director for approval.
15. Contact the PHMSA for those events not otherwise a reportable incident, and to
the extent practicable, regarding identified belowground leak indications in the pipe body, pipe
seam or girth weld other than minor coupling leak indications at the e-mail address provided.
16. Once approved by the Director, each RWP will become incorporated into the
Order. These plans may be revised as necessary based on new information or improvement
opportunities identified in the course of completing the work and in such case shall be submitted
to the Director for prior approval. The Director may approve plan elements incrementally.
17. Implement the RWP elements incrementally as approved by the Director,
including any revisions to the plan. The results of all actions taken in accordance with the
approved plan must be available for review by the PHMSA or the PHMSA representative.
18. Consent Order Documentation Report (CODR). Respondent must create and
submit on a quarterly basis, a CODR. The intent is for the CODRs to summarize all activities
and documentation associated with this Order and to identify any activities or documentation for
the period reflected in previous report activities so the status of any item in the Order is reflected
in each report. When the Respondent has concluded all the required items in this Order, it will
submit a final CODR to the Director. This will allow the Director to complete a thorough review
of all actions taken by the Respondent with regards to this Order prior to approving the closure
of this Order.
19. It is requested that PEPL maintain documentation of the costs associated with
implementation of the Order, and include in each report submitted pursuant to Item 19, the to-
date total costs associated with: (1) preparation and revision of procedures, studies and analyses;
(2) physical changes to pipeline infrastructure, including repairs, replacements and other
modifications; and (3) environmental remediation, if applicable.
20. The Director may grant an extension of time for compliance with any of the terms
of the Order upon a written request, timely submitted, demonstrating good cause for an
extension.
21. For all submissions based upon this Order that requires the approval of the
Director, the Director may (a) approve the submission in whole or in part; (b) impose specific
conditions; (c) modify the submission to cure any deficiencies; (d) reject the submission in whole
or in part; or (e) any combination of the above.
22. PEPL may appeal any decision of the Director to the Associate Administrator for
Pipeline Safety. Decisions of the Associate Administrator are final.
III. Review and Approval Process
23. With respect to any submission under Section II of this Consent Agreement that
requires the approval of the Region Director, the Director may: (a) approve, in whole or in part,
12



the submission, (b) approve the submission on specified conditions, (c) disapprove, in whole or
in part, the submission, or (d) any combination of the foregoing. If the Region Director approves,
approves in part, or approves with conditions, Respondent will take all action as approved by the
Director, subject to Respondent's right to invoke the dispute resolution procedures in Section IV
with respect to any conditions the Director identifies. If the Director disapproves all or any
portion of the submission, the Director will provide Respondent with a written notice of the
deficiencies. Respondent will correct all deficiencies within the time specified by the Director
and resubmit it for approval.
IV. Dispute Resolution
24. The Region Director and Respondent will informally attempt to resolve any
disputes arising under this Consent Agreement. If Respondent and the Region Director are
unable to informally resolve the dispute within 15 days, Respondent may request in writing,
within 10 days, a written determination resolving the dispute from the Associate Administrator
for Pipeline Safety providing all information that Respondent believes is relevant to the dispute.
If the request is submitted as provided herein, the Associate Administrator will issue a final
determination in writing. The existence of a dispute and the PHMSA's consideration of matters
placed in dispute will not excuse, toll, or suspend any term or timeframe for completion of any
work to be performed under this agreement during the pendency of the dispute resolution process
except as agreed by the Region Director or the Associate Administrator in writing.
V. Enforcement
25. This Consent Agreement, as adopted by the Consent Order, is subject to all
enforcement authorities available to the PHMSA under 49 U.S.C. § 60101, et seq., and 49 C.F.R.
Part 190. All work plans and associated schedules set forth or referenced in Section II will be
automatically incorporated into this Consent Agreement and are enforceable in the same manner.
VI. Recordkeeping and Information Disclosure
26. Unless otherwise required in this Consent Agreement, Respondent agrees to
maintain records demonstrating compliance with all requirements of this Consent Agreement for
a period of at least five years following completion of all work to be performed. For any reports,
plans, or other deliverables required to be submitted to the PHMSA pursuant to this Consent
Agreement, Respondent may assert a claim of business confidentiality or other protections
applicable to the release of information by the PHMSA, covering part or all of the information
required to be submitted to the PHMSA pursuant to this agreement in accordance with 49 C.F.R.
Part 7. Respondent must mark the claim of confidentiality in writing on each page, and include a
statement specifying the grounds for each claim of confidentially. The PHMSA determines
release of any information submitted pursuant to this Consent Agreement in accordance with 49
C.F.R. Part 7, the Freedom of Information Act, 5 U.S.C. § 552, DOT and/or the PHMSA
policies, and other applicable regulations and Executive Orders.
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VII. Effective Date
27. The “Effective Date” as used herein is the date on which the Order is issued by
the Associate Administrator incorporating the terms of this Agreement. Unless specified to the
contrary, all deadlines for actions required by this Consent Agreement run from the Effective
Date of this Order.
VIII. Modification
28. The terms of this Consent Agreement may be modified by mutual agreement of
the Parties. Such modifications must be in writing and signed by both parties.
IX. Termination
29. This Consent Agreement terminates upon completion of all terms set forth in
Section II (Corrective Measures) as determined by the Director, Central Region. Respondent
may request written confirmation from the PHMSA when this Consent Agreement is terminated.
To the extent ongoing monitoring is required, the PHMSA may terminate this Consent
Agreement with respect to all other requirements with the exception of such monitoring. Nothing
in this Consent Agreement prevents Respondent from completing any of the obligations earlier
than the deadlines provided for in this Agreement.
X. Ratification
30. The Parties’ undersigned representatives certify that they are fully authorized to
enter into the terms and conditions of this Consent Agreement and to execute and legally bind
such party to this document.
31. The Parties hereby agree to all conditions and terms of this Consent Agreement:
For Respondent:
______________________________
Ryan K. Coffey
Executive Vice President Operations
Panhandle Eastern Pipe Line Company, LP
______________________________
Date
14



For the PHMSA:
_____________________________
Allan Beshore
Director, Office of Pipeline Safety
PHMSA Central Region
U.S. Department of Transportation
_____________________________
Date
15

320141008S_Consent Order_04162015_text.pdf

April 16, 2015
Mr. Kelcy L. Warren
Chief Executive Officer
Energy Transfer Partners, LP
3738 Oak Lawn Avenue
Dallas, Texas 75219
Re: CPF No. 3-2014-1008S
Dear Mr. Warren:
Enclosed please find a Consent Order incorporating the terms of the Consent Agreement
between Pipeline and Hazardous Materials Safety Administration and your subsidiary,
Panhandle Eastern Pipeline Company, LP, that was executed on April 1, 2015. Service of the
Consent Order and Consent Agreement by certified mail is deemed effective upon the date of
mailing, or as otherwise provided 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. Allan Beshore, Director, Central Region, PHMSA
CERTIFIED MAIL - RETURN RECEIPT REQUESTED



U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, D.C. 20590
______________________________________________
In the Matter of )
)
)
Panhandle Eastern Pipe Line Company, LP, a subsidiary of Energy Transfer Partners, LP, )
)
Respondent. )
______________________________________________)
) CPF No. 3-2014-1008S
CONSENT ORDER
By letter dated December 24, 2014, the Pipeline and Hazardous Materials Safety Administration
(PHMSA), Office of Pipeline Safety, issued a Notice of Proposed Safety Order (Notice) to
Panhandle Eastern Pipe Line Company, LP (PEPL or Respondent), a subsidiary of Energy
Transfer Partners, LP (ETP) in this case.
In accordance with 49 C.F.R. § 190.239, the Notice alleged that conditions existed on PEPL’s
pipeline system that might pose a pipeline integrity risk to public safety, property, or the
environment. The Notice also proposed that PEPL take certain corrective measures to remedy
the alleged conditions and ensure that the public, property, and the environment were protected
from the potential risk.
In response to the Notice, Respondent requested an informal consultation, whereupon the parties
engaged in good-faith settlement discussions that resulted in the Consent Agreement attached to
this Order and that settles all of the allegations in the Notice.
Accordingly, the foregoing Consent Agreement is hereby approved and incorporated by
reference into this Order. The Respondent is hereby ordered to comply with the terms of the
Consent Agreement, effective immediately.
Pursuant to 49 U.S.C. 60101, et seq., failure to comply with this Consent Order may result in the
assessment of civil penalties of up to $200,000 per violation per day, or in the referral of the case
for judicial enforcement.



CPF No. 3-2014-1008S
Page 2
The terms and conditions of this Consent Order are effective upon service in accordance with 49
C.F.R. § 190.5.
___________________________________ __________________________
Jeffrey D. Wiese Date Issued
Associate Administrator
for Pipeline Safety

320141008S_Closure Letter_02212020_text.pdf

CERTIFIED MAIL - RETURN RECEIPT REQUESTED
February 21, 2020
Mr. Kelcy L. Warren
Chief Executive Officer
Energy Transfer Partners, L.P.
3738 Oak Lawn Avenue
Dallas, Texas 75219
CPF 3-2014-1008S
Dear Mr. Warren:
On December 24, 2014, the Pipeline and Hazardous Materials Safety Administration
(PHMSA), Office of Pipeline Safety, issued to your subsidiary, Panhandle Eastern Pipe
Line Company L.P. (PEPL), a Notice of Proposed Safety Order (Notice) in the above-
referenced case. The Notice resulted from an investigation of the safety of PEPL’s
pipeline system, including incidents that occurred on November 28, 2013, on PEPL's 400
line approximately 4.7 miles downstream of the Houstonia compressor station near
Hughesville, Missouri and the October 13, 2014 failure on the 100 line near Centerview,
Missouri. Both incidents resulted in significant fire and emergency response requirements.
As a result of the investigation, the Notice alleged apparent conditions existed on the
PEPL’s pipeline system that posed a pipeline integrity risk to the public safety, property or
the environment.
In response to the Notice, PEPL requested an informal consultation, whereupon the
parties engaged in good faith discussions that resulted in a Consent Agreement that was
signed by PEPL and OPS Director, Central Region, on April 1, 2015. On April 16,
2015, a Consent Order incorporating the terms of the Consent Agreement was issued
resolving the Notice.
Since its issuance, PEPL has worked toward completing the requirements of the Consent
Agreement and Order. In a letter dated January 15, 2020, PEPL submitted its final quarterly
report, as required by the Consent Agreement and Order, and requested closure of the case.
PHMSA OPS Central Region has reviewed PEPL’s request and confirms that PEPL has
met the terms of the Consent Agreement and Order and is hereby closed. Furthermore,
consistent with the provisions in Section IX, Termination, of the Consent Agreement and



Order, PHMSA will continue to monitor PEPL’s ongoing implementation of the
processes and procedures created to comply with the Consent Agreement. The closure of
the Consent Agreement and Order does not impact PEPL’s obligations with respect to
any other enforcement action, either by PHMSA or another agency.
Thank you for your cooperation in this matter.
Sincerely,
Allan C. Beshore
Director, Central Region, OPS
Pipeline and Hazardous Materials Safety Administration
cc: Mr. Eric Amundsen, Senior Vice President – Operations, Energy Transfer, L.P.
Mr. Alan Mayberry, Associate Administrator of Pipeline Safety, PHMSA

320141008S_Notice of Proposed Safety Order_12242014_text.pdf

VIA CERTIFIED MAIL AND FAX TO: (214-981-0700)
December 24, 2014
Mr. Kelcy L. Warren
Chief Executive Officer
Energy Transfer Partners, L.P.
3738 Oak Lawn Avenue
Dallas, Texas 75219
Re: CPF No. 3-2014-1008S
Dear Mr. Warren:
Enclosed please find a Notice of Proposed Safety Order (Notice) issued in the above-referenced
case. The Notice proposes that you take certain measures with respect to Energy Transfer
Partners, L.P./Panhandle Eastern Pipe Line Company system (ETP/PEPL). Your receipt of the
Notice constitutes service of this document under 49 C.F.R. § 190.5.
We look forward to a successful resolution of this matter to ensure pipeline safety. Please direct
any questions on this matter to me at (816) 329-3800.
Sincerely,
Allan C. Beshore
Director, Central Region, OPS
Pipeline and Hazardous Materials Safety Administration
Enclosures: Notice of Proposed Safety Order and Copy of 49 C.F.R. § 190.239
cc: Ryan Coffey, Executive Vice-President



U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
CENTRAL REGION
KANSAS CITY, MISSOURI 64106
____________________________________
In the Matter of )
Energy Transfer Partners, L.P., )
Panhandle Eastern Pipe Line Company, ) CPF No. 3-2014-1008S
)
)
)
Respondent. )
____________________________________)
NOTICE OF PROPOSED SAFETY ORDER
Background and Purpose
Pursuant to Chapter 601 of Title 49, United States Code, the Pipeline and Hazardous Materials
Safety Administration (PHMSA) has initiated an investigation of the safety of Energy Transfer
Partners, L.P. Panhandle Eastern Pipe Line Company’s (ETP/PEPL) pipeline system, including
incidents that occurred on November 28, 2013, on ETP/PEPL’s 400 line approximately 4.7 miles
downstream of the Houstonia compressor station near Hughesville, Missouri and the October 13,
2014 failure on the 100 line near Centerview, Missouri. Both incidents resulted in significant
fire and emergency response requirements.
As a result of the investigation, it appears that conditions exist on the ETP/PEPL pipeline system
that pose a pipeline integrity risk to public safety, property or the environment. Pursuant to 49
U.S.C. § 60117(l), PHMSA issues this Notice of Proposed Safety Order (Notice), notifying you
of the preliminary findings of the investigations and proposing that you take measures to ensure
that the public, property, and the environment are protected from the potential risk.
Preliminary Findings
• As of 2014, Energy Transfer is a Texas-based company that is engaged in the operation
and/or ownership of approximately 71,000 miles of pipeline. This pipeline mileage
includes natural gas, natural gas liquids (NGLs), refined products, and crude oil
pipelines. In 2012, Energy Transfer acquired the Southern Union Company and
expanded its natural gas pipeline assets to more than 20,000 miles, including gathering



2
and transportation related assets. The Panhandle Eastern Pipe Line Company system
was a portion of this acquired mileage.
• ETP/PEPL’s pipeline is a natural gas transmission system comprised of a combination of
pipelines and storage fields with approximately 6,000 miles of interstate pipeline,
portions of which are capable of bi-directional movement. This ETP/PEPL system is
comprised of five large transmission pipelines (100 Line, 200 Line, 300 Line, 400 line,
and 500 line), and numerous laterals. This pipeline system traverses the states of
Kansas, Missouri, Illinois, Indiana, Ohio, and Michigan.
• PHMSA and/or State Pipeline Safety partners have repeatedly addressed concerns with
ETP/PEPL on various pipelines within the ETP/PEPL pipeline system associated with
corrosion, coupling failures, inadequate procedures, and controls. To remedy these
issues, PHMSA has engaged in a number of inspections and has even issued Corrective
Action Orders to ETP/PEPL. However, significant improvements associated with
corrosion, coupling failures, inadequate procedures, and controls have not occurred. A
few of these significant cases and events are named below:
o PHMSA issued CPF 3-2008-1002 as a result of a failure that occurred on the
ETP/PEPL Glenarm 200 Line at approximately MP 3, near Pawnee, Illinois on
4/27/2007. The failure ejected a 109-inch long section of 22-inch diameter pipe,
releasing 38 mmcf of natural gas that ignited. The rupture and resulting fire
required the evacuation of a residence and the death of farm animals. The pipe that
failed was installed in 1940, seamless, 0.281-inch wall thickness, X42,
manufactured by National tube, and coated with a field applied Bitumastic coal tar
epoxy. The maximum allowable operating pressure (MAOP) was 800 psig and the
pressure at the time of failure was 788 psig. The failure was due to external
corrosion. Evidence from the case indicates that “Respondent's atmospheric coating
system installed in the area of the pipe that failed was in poor condition as early as
2003, that Panhandle discovered and documented the poor condition of the coating at
that time and also in 2005, and that the company took no action to remediate the
external corrosion prior to the Incident.”
o On August 27, 2007, ETP/PEPL experienced a longitudinal crack in the body of the
pipe at Waverly Storage field in Morgan County, Illinois. This failure was on pipe
installed in 1986, 8 inches in diameter, reported as 0.180 inch wall thickness, X42,
ERW, manufactured by Republic. The MAOP was 845 psig and the pressure at the
time of the failure was 787 psig. The cause of the failure was reported by the
operator to be internal corrosion associated with a low spot in the pipeline.
o On November 30, 2007, PHMSA issued CPF 3-2007-1016H as the result of a failure
on the 400 Line near the town of Haven, Kansas (date of the failure was
11/21/2007). The incident occurred at Mile Post (MP) 3.1 and resulted in a large
fireball requiring multiple emergency response entities and nearby county road
closures. The failed pipe section was installed in 1962, comprised of 30-inch
nominal diameter, 0.312-inch wall thickness, Grade X60, electric flash-welded
(EFW) pipe manufactured by A.O. Smith with coal tar coating and MAOP of 900



3
psig. The pressure at the time of the failure was 897 psig. This segment of pipeline
on the 400 line crossed the Arkansas River and several state highways. This CAO
was the second CAO issued for this line segment (CAO 3-2001-1001H was the
first) and was the third similar failure (first occurring in 1990 at MP 0.0 and the
second in 2000 at MP 6.1.) All three failures were the result of selective seam
corrosion.
o On June 20, 2008, PHMSA issued CPF 4-2008-1012M to ETP/PEPL as the result of
an integrity management inspection. Numerous procedural revisions were required
and these affected significant areas such as High Consequence Area (HCA)
identification.
o On July 1, 2008, PHMSA issued CPF 4-2008-1013M to ETP/PEPL regarding
operator qualification requirements and identified many areas for procedural
amendments. These areas included corrosion related topics such as close interval
survey, various other covered tasks and how contractor qualifications suspensions
would occur after incident investigations.
o On August 25, 2008, at approximately 8:51 a.m., a rupture occurred on the
ETP/PEPL Houstonia 200 Line near Mile Post 21.6. The failed section of the
pipeline was located in a rural area west of Pilot Grove, Missouri in Cooper County.
The longitudinal rupture in the pipe body created a 50-foot by 33-foot by 7-foot
deep crater in the ground. Two pipeline sections totaling 28 feet in length and a
coupling were ejected from the crater up to a distance of 300 feet from the rupture
site. The 24-inch pipe was installed in 1937, 0.280 wall thickness, 48,000 SMYS,
manufactured by A.O. Smith, and EFW seam. The MAOP was 800 psig and the
pipeline pressure at the time of the failure was reported to be 790 psig. The cause
of the rupture was external corrosion.
o On May 13, 2009, PHMSA issued ETP/PEPL Corrective Action Order CPF 3-2009-
1009H following a failure on the 24-inch 200 Line near Rockville, Indiana on May
5, 2009. Fifty two people were evacuated. The pipe was installed in 1940,
manufactured by National Tube, reported to be 0.312 inch wall thickness, 35,000
SMYS, and seamless. The MAOP was 800 psig and pressure was 784 psig at the
point of the failure. The cause of this failure was determined to be external
corrosion. Additional work performed as a result of this order provided significant
indications of external corrosion in various sections of the 200 Line.
o On May 20, 2009, ETP/PEPL experienced a failure on the 200 Line due to a coupling
pulling apart near Fayette, Missouri and County Road 427. Fourteen people were
evacuated. The MAOP was 800 psig and pressure at the time of the failure was 567
psig.
o On May 17-21, 2010, PHMSA conducted an inspection of the ETP/PEPL written
operations and maintenance procedures. As a result of the inspection, PHMSA
issued CPF 3-2010-1006M on December 21, 2010, identifying 20 procedures that



4
were inadequate to assure safe operations. This enforcement action resulted in an
Order Directing Amendment specific to IR drop inclusion for accurate cathodic
protection measurement. The final implementation of this amendment has yet to be
completed by ETP/PEPL.
o On December 29, 2010, PHMSA issued warning letter 3-2010-1008W to ETP/PEPL.
Item 1 identified a potential ignition source associated with wiring for a regulator
heater at the A.P. Green delivery point and Item 2 noted that ETP/PEPL had not
designed and constructed the Peoria Lateral 3 Gate delivery point in such a manner
as to ensure that damage to one control line would not make the other over pressure
device inoperative.
o On April 25, 2011, ETP/PEPL experienced a failure on the 22-inch 200 Line near
Manchester, IL. The pipe at this location has a 0.281 inch wall thickness, seamless,
and X42. The cause of the failure was a coupling pulling apart at MP 31.5. The
MAOP was 800 psig and the pressure at the time of the failure was 749 psig.
o On May 29, 2011, ETP/PEPL experienced a failure in the Borchers Storage field near
Meade, Kansas. The pipe was installed in 1981, manufactured by Tex-tube, was
6.625 inches in nominal diameter, 0.219 inch wall thickness, SMYS 46,000, and
High Frequency ERW, coated with a field applied epoxy. The MAOP was 1,875
psig and the estimated pressure at the location of the failure was 1,639 psig. The
cause of the failure was determined to be internal corrosion.
o On July 1, 2013, PHMSA issued CPF 3-2013-1011M as a result of an inspection
during May 24-26, 2011. This enforcement action identified several deficiencies,
including that ETP/PEPL procedures were inadequate because its Public Awareness
Plan did not include a process that clearly defined how to establish proper
notification areas and distance on each of their pipeline system that affects the
public stakeholder audience including other appropriate factors such as the potential
impact radius (PIR) and the alternate maximum allowable operating pressure
(AMAOP) conditions.
o On April 9, 2014, PHMSA issued a final order for CPF 3-2013-1015. ETP/PEPL had
operated its meter and regulator stations and associated pipeline segments at
Centertown, Missouri and Auburn, Illinois above the MAOP. On October 28, 2011,
ETP/PEPL's working and monitor regulators at Centertown's M&R station
malfunctioned allowing the pressure to reach approximately 486 psig exceeding the
MAOP and the pipeline operated above 110 percent psig for 9 hours. Similarly on
April 6, 2012, ETP/PEPL working and monitor regulators at Auburn's M&R station
froze-up resulting in the pressure downstream of the station reaching approximately
550 psig exceeding MAOP for approximately 1-1/2 hours.
o During June 18-July 20, 2012 PHMSA inspected ETP/PEPL facilities in Kansas and
Missouri. Discoveries associated with the inspection revealed a lack of prompt
remedial action to cathodic protection (CP) deficiencies, a lack of tests to assure



5
electrical isolation of casings, a lack of sufficient test stations or other contact
points to determine the adequacy of cathodic protection on the 100 and 200 Lines,
and an insufficient continuing program to minimize the detrimental effects of
interference currents on the affected pipeline systems of the 100 and 200 Lines.
PHMSA also identified that documentation associated with a periodic review of
work done by operator personnel to determine the effectiveness and adequacy of
procedures was not available.
• During September and October in 2013, representatives of the Michigan Public Service
Commission, acting as an interstate agent for PHMSA, inspected ETP/PEPL records
and facilities in Howell, Michigan. As a result of the inspection, PHMSA issued
warning letter 3-2014-1006W. This warning letter identified concerns with the
integrity management program implementation regarding HCA designations and
associated documentation.
• On September 24, 2013, ETP/PEPL experienced a coupling leak near New Franklin,
Missouri. Interconnect piping located at the 5 gate valve between the 100 and 200 lines
contained a 10-inch coupling. The interconnect line had been cut and capped when a
valve was removed in 2010 from the 200 line. The coupling was left on the capped
interconnect when the maintenance was performed in 2010.
• On November 28, 2013, ETP/PEPL’s 400 line failed approximately 4.7 miles
downstream of the Houstonia compressor station near Hughesville, Missouri. The
blowing gas ignited and nine people were evacuated. The failed joint of 30-inch pipe
was ejected approximately 200 feet from the original location. The pipe was installed
in 1962, 0.312 inch wall thickness, API5L X60, DSAW seam, manufactured by Kaiser
Steel Corporation and was coated with coal tar enamel. A close interval survey had
been conducted in 2013. The MAOP of the pipeline segment was 900 psig and the
operating pressure at the time of failure was reported as 893 psig. The pipeline has
received several inline inspection (ILI) runs. Metallurgical examination determined the
root cause of the failure to be corrosion.
o As a result of discussions with PHMSA, ETP/PEPL performed an internal and third
party Root Cause Failure Analysis (RCFA) associated with the November 28, 2013
Houstonia 400 line failure. These failure investigations as presented to PHMSA
identified needed improvements in the maintenance of cathodic protection systems
and the prioritization of corrosion concerns, personnel training, data integration
associated with corrosion control and environmental and ILI data, personnel
understanding budget requests as it may relate to unplanned work, the number and
locations of ILI data confirmation digs, the use of metal loss interaction rules by the
ILI vendors, and the anomaly interactions effects on failure pressure ratio (FPR)
calculations. A significant finding in the review of the records was disconnected
negative cables on the 100, 300 and 400 lines as a result of a 2007 project for a new
ground bed installation on the 200 Line. As built drawings did not reflect this
connection. Recommendations from the ETP/PEPL internal Houstonia 400 line



6
RCFA (dated June 18, 2014) were provided in the areas of CP analysis and
response, Personnel Training and Priorities, and Inline Inspection processes.
o During the initial investigation by PHMSA of the ETP/PEPL November 28, 2013
failure on the 400 line, it was determined that ETP/PEPL was in the process of
developing corrosion growth rates and this had not been completed.
• On June 19, 2014, ETP/PEPL released liquid from the Olpe 100 compressor station
discharge in preparation to repair a leak that was downstream of the station. The leak
was from a 3” crack in a long seam (.24" diameter pipe, .281" wall thickness, SSAW
seam, National Tube, Bitumastic coating). This leak was discovered during an airborne
Lidar leak survey on the 100 and 200 lines from Haven to Louisburg (329.9 miles).
Also discovered during this leak survey were other significant findings. While there
were no local residents evacuated as a result of the liquid released from the natural gas
pipeline, media attention occurred and a local golf course five ponds, two small areas
with standing water, one small drainage ditch on various properties, five houses,
soybean crops, gardens, and pasture land were affected. The impact to livestock was
unclear. Leaks identified included at least five coupling leaks and resulted in several
repair projects.
• On July 7, 2014, ETP/PEPL provided PHMSA with a notification regarding a reboiler
vessel event that resulted in an emergency shutdown (ESD) of the Borchers Storage
Field in southwestern Kansas due to a fire. The vessel fractured and the root cause of
this event is in review.
• On July 24, 2014, ETP/PEPL delivered gas to DTE Energy from approximately 12:00
P.M. to 4:00 P.M. EST. Shortly after receipt of gas from ETP/PEPL, DTE began
receiving numerous odor complaints in the community. DTE energy investigated and
determined that over odorized gas had come from ETP/PEPL and DTE shut off the gas
from ETP/PEPL. ETP/PEPL was contacted and informed DTE that it was not an
ETP/PEPL problem. DTE received nearly 1,000 odor complaints over 2 days and DTE
responded by dispatching field technicians. After further investigation, ETP/PEPL
concluded that ETP/PEPL had delivered the over-odorized gas to DTE.
• On October 13, 2014, a fire and explosion occurred on the 100 line near Centerview,
Missouri. ETP/PEPL reported a release of gas to the National Response Center (NRC)
on October 13, 2014 at 12:07 pm EDT (NRC Report #1098139). No fatalities or
injuries occurred. PHMSA initiated an investigation of the incident, which involved an
on-site investigation at the failure location. The failure resulted in evacuations
associated within approximately one mile radius and a county road closure (701). All
residents were allowed to return to their homes by 2:00 pm CDT.
o At approximately 10:13 am CDT on October 13, 2014, ETP/PEPL control room
personnel observed a sudden pressure drop on their SCADA system indicating a
possible failure on the Louisburg 100 pipeline. The control room then received a
call at 10:18 am CDT from the Johnson County, Missouri 911 call center that



7
reported a natural gas release at 21 Northwest 701 Road in Centerview, Missouri.
At this time, the natural gas had not ignited. The control room received a second
call from the 911 center at 10:28 am CDT to report a fire at the scene. The control
room personnel notified the ETP/PEPL Kansas City District office at 10:20 am
CDT and at 10:28 am CDT, operations personnel were dispatched to the upstream
and downstream valve locations and the failure location.
o The failure resulted in the ejection of approximately 22 feet of 22-inch diameter pipe
140 feet from the pipeline. The failure happened 600 feet east of Road 701 and 400
feet south of the nearest structure (a barn). The structure did sustain damage from
flying debris.
o The 100 line has been repaired and is currently operating at a restricted 75 psig in the
area of the failure. ETP/PEPL has removed the failed section of pipe and sent the
pipe to a third-party metallurgical laboratory for evaluation. A repair plan was
submitted initially, PHMSA supplied comments back, and PHMSA and ETP/PEPL
agreed to a revised restart plan consisting only of the repair with the restricted
pressure of 75 psig at this time.
o Line 100 is 22-inch diameter, mainly of 0.312 -inch wall thickness, 30,700 estimated
yield strength pipe, manufactured by National Tube in 1931 with lap welded
longitudinal seams. The coating is Bitumatstic and the pipeline is cathodically
protected with impressed current. The pipe joints in the Louisburg 100 Line are
joined together by either welding or by using mechanical couplings. A few of the
couplings have been reinforced on the 100 Line over the years.
o The maximum allowable operating pressure (MAOP) for the 100 Line is 475 psig at
this location and the pressure at the time of the failure was approximately 441 psig.
A hydrostatic test was conducted as part of the 1953 100 Line test program to a
pressure of 736 psig at the high point on 8/23/1953 for a minimum of 4 hours.
o The original 625 psig MAOP for this section was reported to have been established
by the five year history of operating pressure from the Louisburg 100 line discharge
pressures between July 1, 1965 and July 1, 1970 and was reduced to 500 psig on
April 1, 2004 by a letter issued by an Executive Officer of the Company on March
14, 2004. This new MAOP was based upon the operating and maintenance (O&M)
history of the line. The new pressure maximum was primarily maintained by
pressure bleeds from the 200 line. Subsequently on 4/2/2012, the pressure on the
Olpe 100 discharge was reduced to 475 psig due to a class location change. It was
determined that it would be easier to maintain a consistent 475 psig pressure using
the pressure bleeds from the 200 line, so the Louisburg 100 Discharge was also
reduced to 475 psig on 4/2/2012.
o The first station immediately upstream of the failure site is Louisburg Station.
Houstonia Compressor Station is the first station downstream. Line 100 crosses
heavily traveled public roadways, including Missouri Highway 50.



8
o The condition or conditions on the pipeline that caused the failure are under
investigation. Evidence indicates that two couplings (one on either end of the
failure pipe joint) were not reinforced prior to the incident. The pipeline remains
coupled in many areas without reinforcement and as a result, the same condition(s)
that caused the failure could be present (or could develop) on other areas of the
pipeline and impair the reliability and serviceability of the pipeline.
o ETP/PEPL performed an inline inspection (ILI) of the pipeline in 2009 with high
resolution magnetic flux leakage (MFL) and caliper tools. The company has
indicated that a review of the ILI information at that time revealed no actionable
features at or near the failure site. There were 29 reported anomalies with metal
loss greater than 80% deep, and 19 possible dents with metal loss. 39 locations
were reported to exist with an RPR less than or equal to 1.39.
• ETP/PEPL routinely operates significant portions (approximately 457 miles) of the
pipeline system over 72 percent SMYS due to historical operating pressures in
accordance with 49 CFR § 192.691(c).
• ETP/PEPL has not submitted a Safety Related Condition Report (SRCR) for PHMSA
Central Region since 1991. This 1991 SRCR available in PHMSA records identified a
general corrosion issue.
• ETP/PEPL shares natural gas transmission safety program relationships with the
following operators under PHMSA jurisdiction. Incidents and enforcement actions for
these entities have not been included in this review summary:
o Energy Transfer (Op ID 32099)
o Florida Gas Transmission (Op ID 5304)
o Sea Robin Pipeline Company (Op ID 18152)
o TransWestern Pipeline Company LLC (Op ID 19610)
o Trunkline Gas Company (Op ID 19730)
o Lee 8 Storage Partnership (Op ID 30786)
o Gulf States Transmission Corporation (Op ID 32323)
o ETC Tiger Pipeline LLC (Op ID 32467)
o Fayette Express Pipeline LLC (Op ID 32469)
o DCP Midstream- PEPL (Op ID 39028)
Proposed Issuance of Safety Order
Section 60117(l) of Title 49, United States Code, provides for the issuance of a safety order, after
reasonable notice and the opportunity for a hearing, requiring corrective measures, which may
include physical inspection, testing, repair, or other action, as appropriate. The basis for making
the determination that a pipeline facility has a condition or conditions that pose a pipeline



9
integrity risk to public safety, property, or the environment is set forth both in the above-
referenced statute and 49 C.F.R. § 190.239, a copy of which is enclosed.
After evaluating the foregoing preliminary findings of fact and considering the age of the
pipeline system, the proximity of the pipeline system to public roadways and populated areas, the
hazardous nature of the product being transported, the pressure required for transporting the
material, the ongoing investigations to determine the conditions that caused the pipeline failures,
the likelihood that the conditions causing the failures could be present or could develop on other
areas of the pipeline, and the likelihood that such conditions could again impair the serviceability
of the pipeline system, it appears that the continued operation of the pipeline system without
corrective measures would pose a pipeline integrity risk to public safety, property, or the
environment.
Accordingly, PHMSA issues this Notice of Proposed Safety Order to notify ETP/PEPL of the
proposed issuance of a safety order and to propose that the company take the measures specified
herein to address the potential risk.
Response to this Notice
In accordance with 49 C.F.R. § 190.239, you have 30 days following receipt of this Notice to
submit a written response to the Regional Director who issued the Notice. If you do not respond
within 30 days, this constitutes a waiver of your right to contest the Notice and authorizes the
Associate Administrator for Pipeline Safety to find facts as alleged in the Notice without further
notice to you and to issue a safety order.
In your response, you may notify the Regional Director that you intend to comply with the terms
of the Notice as proposed, or you may request that an informal consultation be scheduled.
Informal consultation provides you with the opportunity to explain the circumstances associated
with the risk conditions alleged in the notice and, as appropriate, to present a proposal for a work
plan or other remedial measures, without prejudice to your position in any subsequent hearing.
If you and PHMSA agree within 30 days of informal consultation on a plan and schedule for you
to address each identified risk condition, we may enter into a written consent agreement
(Agreement). PHMSA would then issue an administrative consent order incorporating the terms
of the agreement.
If a consent agreement is not reached, or if you have elected not to request informal consultation,
you may request an administrative hearing in writing within 30 days following receipt of the
Notice or within 10 days following the conclusion of an informal consultation that did not result
in a consent agreement, as applicable. Following a hearing, if the Associate Administrator finds
the facility to have a condition that poses a pipeline integrity risk to the public, property, or the
environment in accordance with 49 C.F.R. § 190.239, the Associate Administrator may issue a
Safety Order.
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



10
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
qualifies for confidential treatment under 5 U.S.C. § 552(b).
In your correspondence on this matter, please refer to CPF 3-2014-1008S and for each document
you submit, please provide a copy in electronic format whenever possible.
Proposed Corrective Measures
Pursuant to 49 U.S.C. § 60117(l) and 49 C.F.R. § 190.239, PHMSA proposes to issue to Energy
Transfer Partners/Panhandle Eastern Pipe Line Company (ETP/PEPL) a Safety Order (Order)
incorporating the following remedial requirements with respect to the ETP/PEPL pipeline system
(100 Line, 200 Line, 300 Line, 400 Line, 500 Line, laterals and all associated piping):
1. Regarding the 100 Line failure occurring on October 13, 2014, ETP/PEPL shall
complete the following:
(A) Within 90 days of the receipt of this Order, ETP/PEPL shall complete a root
cause failure analysis (RCFA) for the 100 Line failure occurring on October
13, 2014, and submit a final report for this RCFA to the Director. The RCFA
must be facilitated by an independent consultant acceptable to the Director
and must document the decision-making process and all factors contributing
to the failure on the 100 line. ETP/PEPL shall submit a summary of suitability
as outlined in Item 4 (A) of this Order for the independent consultant
proposed to be used for the RCFA to the Central Region Director for review.
PHMSA will review the submitted information and will notify ETP/PEPL if
the proposed candidate is unacceptable. The RCFA must provide a detailed
review of all SCADA and control related activities related to the response to
the failure. If SCADA or control activities are identified as contributing
factors during this review, recommended actions to address the contributing
factors shall be included in the report and discussed with the Director to
develop an appropriate implementation schedule.
(B) Within 45 days of receipt of this Order, complete mechanical and
metallurgical testing and failure analysis of the failed pipe, including an
analysis of soil samples and any foreign materials. Complete the testing and
analysis as follows:
i. Document the chain-of-custody when handling and transporting the
failed pipe section and other evidence from the failure site.
ii. Within 10 days of receipt of this Order, submit the testing protocols
and proposed testing laboratory to the Director.



11
2. (C) (D) (E) iii. Continue to update the Director of mechanical and metallurgical
testing and additional proposed dates with enough notice to allow for
an OPS representative to witness the testing.
iv. Ensure that the testing laboratory provides any report, whether draft or
final, in its entirety to the Director at the same time it is presented to
ETP/PEPL.
Provide to PHMSA a restart plan for the Director’s approval prior to resuming
operations at pressures above 75 psig on the pipeline segment from 105 to 106
gate. The restart plan shall include the following:
i. Instrumented leak survey between 105 and 106 gate to include
associated farm taps or temporary school line replacements. Any leaks
found must be remediated before continuing on with the restart plan.
ii. Must specify a daylight restart and include advance notification with
the local emergency response officials.
iii. Must include reinforcing or removing all 100 Line couplings,
including any that are on the interconnect piping, located on the
property associated with the failure or the adjacent road crossing.
Provide to PHMSA a plan to reinforce or remove all 200 Line couplings on
the property or the adjacent road crossing associated with failure within 1 year
of the receipt of this Order. Completion dates for this activity will be
discussed with the Director and approved by PHMSA.
Develop a plan within 1 year of the receipt of this Order, that includes a depth
cover survey, to implement either reinforcing, removing, or abandoning all
couplings on the 100 and 200 Lines located within 220 yards or the calculated
PIR, whichever distance is greater, of structures, roads, airport, walking paths,
playgrounds or parks, runways, and railroad tracks. The reinforcement,
removal or abandonment of the couplings located in these areas shall be
completed within no more than 3 years from the receipt of this Order. This
plan shall include couplings that may be located on interconnected piping
between the pipelines (i.e. between the 100 and 200 line, between the 200 and
300 line).
i. As part of this plan, for those couplings located within the above areas
identified in E above that are determined to be less than 3 feet in
depth, implement reinforcement, removal or abandonment activities
for those couplings on an expedited basis, not to exceed completion
within 1 year.
Within 90 days after receipt of this Order, ETP/PEPL shall work with PHMSA to
clarify or address all comments provided by PHMSA to the 400 line Houstonia
RCFA. ETP/PEPL shall provide for the Central Region Director’s review and



3. 12
approval an implementation plan and schedule addressing each finding and
recommendation identified in the Root Cause Failure Analyses on the Houstonia 400
line failure (whether internal or external third party). Any finding or recommendation
that would exceed one year for implementation would be identified and reviewed for
concurrence by the Central Region Director. As part of the implementation plan,
integrate the findings of the root cause failure analyses into other data integration
efforts and work plan efforts. The following actions shall also be included as part of
the implementation plan:
(A) Elements that address PHMSA comments to the RCFA.
(B) Complete a job task analysis associated with corrosion technician job
responsibilities. Identify work load per corrosion technician and determine
task priorities. Utilizing a third party specialist, determine resource
allocations for all corrosion control maintenance activities.
(C) Develop a plan and strategy to implement effective technical support of field
personnel. Determine metrics for this support process and develop a written
annual review report that discusses the metrics, program usage, successes and
area of needed improvement. Reports shall be available for PHMSA review
upon request.
(D) Require management review of corrosion technician completed work and
submitted paperwork.
(E) Develop a work management system and process requirements to review
corrosion technician work products and submitted paperwork to ensure that
capital or expense related work is funded to correct deficiencies on the
pipeline system in a timely fashion.
(F) Review and correct as needed: bonding, cathodic protection system junction
points, and rectifier performance for all pipelines.
Within 180 days from receipt of the Order, conduct airborne instrumented leak survey
or an instrumented ground based leak survey (walking the pipeline ROW using Flame
Ionization units) of the entire ETP/PEPL pipeline system.
(A) Within 60 days of the completion of the leak survey, provide a prioritized
schedule for repair or remediation of any leak indication based on the
following criteria:
i. Any leak identified as an imminent public safety threat (as defined
through joint agreement by PHMSA and ETP/PEPL) shall be
immediately remediated;
ii. Leak indications that are found to exist in an HCA, or Class 3, or
Class 4 location;



4. 13
iii. Leak indications discovered at a location on the system located within
220 yards or the calculated PIR, whichever distance is greater, from
any structure or building intended for human occupancy or a location
intended for an outdoor place of assembly;
iv. Leak indications discovered within the right-of-way of an active
railroad, paved road, street, or highway, airport runway;
v. Leak indications discovered in an area where the pipeline is operating
above 72% SMYS;
vi. All other leak indications.
Engage a third party consultant (Consultant) acceptable to the Central Region
Director to review and evaluate ETP/PEPL current or proposed processes,
procedures, and data systems associated with the integrity and safety of the
ETP/PEPL system. Such action may include physical inspection, testing, repair, or
other appropriate action to remedy the identified risk condition.
(A) ETP/PEPL will propose three potential Consultants with associated
credentials to the Central Region Director for review. ETP/PEPL will
research, review, develop, and submit a summary of suitability outlining the
capabilities, qualifications, experience, and relevant work history of at least 3
potential Consultant candidates to the Central Region Director for review. A
similar summary shall be submitted for each sub-consultant proposed to be
utilized, if applicable. PHMSA will review the submitted information and
will notify ETP/PEPL if any of the proposed candidates are unacceptable.
Once 3 Consultant candidates have been found acceptable to PHMSA,
ETP/PEPL shall select the Consultant to be utilized for this Order and finalize
its scope of work. The Consultant’s proposed scope of work will be submitted
to the Central Region Director for review and approval. Each submitted
summary shall, at a minimum, include the following:
i. A listing of key personnel to be utilized on each item in the Order.
ii. Qualifications and relevant experience of key personnel in the specific
areas of expertise necessary for each item in the Order.
iii. Availability of key personnel and resources to assure a timely completion
of each item in the Order.
iv. A summary of work performed by key personnel for ETP/PEPL in the past
5 years.
v. A summary of any potential conflicts of interest that might be relevant to
the work to be performed pursuant to this Order.



14
vi. vii. (B) (C) (D) A statement executed by an officer of ETP/PEPL that it has reviewed and
found that the proposed Consultant candidate is acceptable to
ETP/PEPL and is capable of performing the work required by this
Order and that no conflicts of interest exist or shall arise if the
proposed Consultant is selected.
A statement executed by ETP/PEPL and the Consultant outlining
measures to be taken to ensure the Consultant performs an independent
and impartial analysis of each item in its scope of work that is required
by this Order.
Within 90 days of the receipt of this Order, the Consultant will produce a
report which will be shared with PHMSA and ETP/PEPL regarding the
current safety and integrity of the ETP/PEPL system. The Consultant shall
review and have access to all relevant data, information systems and
applications (developed, created or maintained), as well as access to
ETP/PEPL personnel applicable to the evaluation of the ETP/PEPL system
safety including but not limited to the integrity management program and
implementation.
Findings and reports, whether draft or final, shall be submitted to PHMSA and
ETP/PEPL simultaneously.
The scope of the review and associated report shall include each segment of
the ETP/PEPL system. This report will include laterals but will not be
intended to focus on compressor, measurement, regulation, or underground
storage facilities. It is possible that general outcomes or recommendations
could be applicable to all types of facilities simply by a process or procedure
revision and this should be identified in the report. The report will identify
improvements needed to ensure and elevate system integrity in all relevant
process, procedures, instrumentation and controls, training and qualification
or data systems. The consultant shall review all relevant assessments,
inspections and integrity records to determine if the appropriate process,
procedure, training and qualifications, instrumentation and controls or data
systems are appropriately implemented. Should a process, procedure,
training, qualification, control or data system be determined to be incorrectly
implemented or identified as less than sufficient for the safety of the public
and protection of the public assets, remedial actions shall be developed to
correct any resulting or identified deficiency. The Consultant will also review
current inspections, assessment and integrity review records for all facilities
which used a process, procedures controls or data systems that were found to
need improvement and will identify actions needed to address any corrective
measure in pipeline integrity and public safety. Recent improvement actions
and procedure changes being contemplated or initiated by ETP/PEPL shall
also be part of this review.



5. 15
(E) The Consultant’s report shall also make recommendations on any near-term
actions necessary to maintain pipeline safety while the Comprehensive Safety
and Integrity Improvement work plan (CSII in item 5 in this Order) is being
developed and implemented.
(F) All proposed actions and improvements identified during the course of this
Order shall be considered for implementation on a prioritized risk basis.
These actions and improvements shall be provided to the Central Region
Director for review and approval. All repair or remediation efforts should be
prioritized based on the severity of the condition, proximity to an HCA,
located in a Class 3 or Class 4 location, located within 220 yards or the
calculated PIR (whichever distance is greater) of a structure or outdoor place
of assembly, or is located within the right-of-way of an active railroad, paved
road, street, or highway, or airport runway, or in an area where the pipeline is
operating above 72% SMYS.
(G) The Consultant must report directly to an ETP executive leadership team
comprised of 3 or more members. PHMSA will also provide periodic input to
the Consultant and Executive leadership team including a kick-off meeting to
identify expectations and address initial scope clarifications. In addition,
quarterly review meetings will occur with PHMSA, the Consultant, and an
ETP/PEPL leadership team representative to discuss the status of the
Consultant’s scope of work and ETP/PEPL work plan progress until such time
as PHMSA and the ETP/PEPL leadership team agree it is no longer
necessary.
Develop a Comprehensive Safety and Integrity Improvement (CSII) work plan for the
entire ETP/PEPL system. ETP/PEPL must submit, for review and approval to
PHMSA, a comprehensive written plan, including timelines for specific actions of
development, process review and implementation that has received the Consultant’s
approval. The Consultant must oversee the creation, execution and implementation
of actions identified in the plan, provide detailed process review, and provide
monitoring summaries to PHMSA and Respondent at the same time. Respondent
must commit to address deficiencies, threats or risks, and necessary improvements
identified in the Consultant’s assessment. This will include process improvements,
repair and/or replacement of high-risk infrastructure and other measures as may be
identified by the Consultant assessment. The plan will be designed to improve four
strategic areas of the ETP/PEPL system performance and must be sufficiently
detailed with specific tasks, milestones, completion dates and reporting summaries.
The four strategic areas are:
(A) Improved Corrosion Control Program Process;
(B) Improved Integrity Management Program Process;
(C) Enhanced Safety and Integrity Culture; and



16
(D) Enhanced Data Systems.
This plan must be submitted to, reviewed and approved by the Director, Central
Region, OPS and include the following items:
(A) Implementation of an Improved Corrosion Control Program Process: The
Consultant shall review all processes, procedures, and data systems associated
with the elements of the ETP/PEPL corrosion control program (including
supporting data systems) for improvements. Revisions shall take into account
and include enhanced procedures such as those that have been modified
through other failures, proposed or planned procedures and processes, internal
and external lessons learned, standard industry practice, and specific areas
identified in previous inspection or enforcement activities (Appendix A).
i. The plan, which will address procedural changes for items listed in
Appendix A, shall be prepared and provided to the Consultant for
review and comments. The plan, including comments incorporated
from the Consultant’s review, will be submitted to the Central Region
Director for review and comment within 90 days of receipt of this
Order.
ii. The plan will identify, prioritize, and mitigate CP system deficiencies.
iii. The items listed in Appendix A will also be reviewed to identify any
facility modifications needed to be implemented to address safety or
integrity concerns. Any facility modifications identified by this review
shall be implemented on an accelerated prioritized time frame.
(B) Develop and implement an Improved Integrity Management Program Process:
Implement an integrity work plan (IWP) that is designed to ensure pipeline
safety and an effective integrity program. The IWP shall be approved by the
Consultant and include a comprehensive review of the ETP/PEPL integrity
management program which identifies and quantifies improvements needed to
process, procedures, data systems and employee training and qualifications.
This plan shall be submitted within 180 days of receipt of this Order to the
Central Region Director for review and comment. During the duration of the
Order, the Consultant will provide oversight for integrity management related
activities, decisions, specifications, processes, calculations, procedures and
program revisions. Whenever the Consultant determines that a pressure
reduction is warranted, based on industry standards, best practices, operating
or maintenance experience, other subject matter expert input, or regulatory
requirements, ETP/PEPL shall implement the pressure reduction and report
this action to the Central Region Director.
i. ETP/PEPL must review and revise the threat assessment, risk
assessment, and continual evaluation procedures based upon the



17
ii. iii. iv. v. vi. vii. (C) integration of all available data, the regulatory requirements and
industry best practices.
ETP/PEPL must also demonstrate that the performance plan and
performance measures, mitigative measures, management of change
process and quality assurance program meet the regulatory
requirements, achieve industry best practice, and prevent incident
reoccurrence.
IWP shall include additional field testing, inspections, and evaluations
to determine whether and to what extent the conditions associated with
the failure, or any other integrity-threatening conditions are present
elsewhere on the ETP/PEPL System.
IWP shall include the performance of repairs or other corrective
measures that fully remediate any integrity-threatening condition
everywhere. Include a detailed description of the repair criteria and
method(s) to be used in undertaking any repairs or other remedial
actions.
The IWP shall include provisions for short-term and long-term
periodic testing and integrity verification measures to ensure the
ongoing safe operation of the ETP/PEPL system considering the
results of the analyses, inspections, previous enforcement actions and
corrective measures undertaken pursuant to the Order; and
The IWP must include, but not be limited to, the elements described in
Appendix B.
On a quarterly basis, or more frequently if needed, provide the
Director with advance notice of scheduled repairs, testing or
assessments.
Review the development and implementation of an Enhanced Safety and
Integrity Culture improvement program. A process to implement this
enhanced safety and integrity culture improvement program shall be
developed within 1 year of the receipt of this Order and submitted to the
Central Region Director for review and comment. The program shall be
designed to promote a system wide culture that encourages reporting and
learning improvements while strengthening training and management of
change.
i. A Reporting and Feedback System: A reporting culture for the
purpose of this Order means creating an environment where
employees or consultants have confidence to report safety concerns
without fear of reprisal. Employees are confident that information
provided will be acted upon.



6. 7. 8. 9. 18
ii. A Learning Environment: A learning culture for the purpose of this
Order is a work environment that is capable of learning from mistakes
and responding to prevent reoccurrence.
iii. Implement those elements as defined in Appendix C.
iv. The Consultant is to review existing and proposed enhancements to the
program to assist with the further development of a reporting and
learning culture and those items identified in Appendix C. An
implementation plan for these enhancements shall be developed and
provided to ETP/PEPL and PHMSA.
v. The Consultant will review the existing MOC process, identify
enhancements and provide an implementation schedule for these
enhancements.
(D) Enhanced Data Systems: The Consultant shall review and provide comments
pertaining to a strategic data system improvement plan that will allow the
effective collection, review, integration and analysis of integrity related data.
The plan will define how ETP/PEPL will perform timely analysis of integrity
related data, recognize integrity threats, identify effective mitigative and
preventative measures, and support effective decision making. This data
system strategic plan shall be completed within 1 year from the receipt of this
Order. This shall be submitted to the Central Region Director for review and
comment. An implementation schedule shall be submitted to the Central
Region Director for approval. This shall include elements as presented in
Appendix D.
The Comprehensive Safety and Integrity Improvement work plan and the IWP
becomes incorporated into the Order and must be revised as necessary to incorporate
the results of actions undertaken pursuant to the Order and whenever necessary to
incorporate new information obtained during the failure investigations and remedial
activities. Submit any such plan revisions to the Director for prior approval. The
Director may approve plan elements incrementally.
Implement the Comprehensive Safety and Integrity Improvement work plan as
approved by the Director, including any revisions to the plan. The results of all
actions taken in accordance with the approved plan must be available for review by
PHMSA or the PHMSA representative.
The Respondent shall notify PHMSA Central Region via the PHMSA PHP300
Accident Team email address within 24 hours of discovery of any leak indication that
is not reported through other requirements in 49 CFR 191 or the elements in this
Order associated with leak survey.
Safety Order Documentation Report (SODR). Respondent must create, revise as
necessary, and submit on a quarterly basis, a Safety Order Documentation Report.
The intent is for the SODRs to summarize all activities and documentation associated



19
with this Order and to identify any activities or documentation for the period reflected
in previous report activities so the status of any item in the Order is reflected in each
report. When the Respondent has concluded all the required items in this Order, it
will submit the final SODR in its entirety to the Director. This will allow the Director
to complete a thorough review of all actions taken by the Respondent with regards to
this Order prior to approving the closure of this Order.
(A) The Director may approve elements in the SODR as noted in item 11 below.
(B) Once approved by the Director, the SODR elements will be incorporated by
reference into this Order. The SODR must include but not be limited to:
i. Table of Contents;
ii. iii. iv. v. vi. vii. viii. ix. Summary of the relevant pipeline failures, and the response activities
applicable to the Houstonia 400 failure, the Louisburg 100 failure or as
may be significant to provisions of this Order including leak metrics
by locations identified (item 3 above) in this Order;
Summary of the pipeline system by pipe data properties associated
with the failures and all prior assessments for the failure areas
(Houstonia 400 failure, Louisburg 100 failure) or as may be significant
to the provisions of this Order;
Summary of all activities under this Order including documentation
associated with the Appendices or the IWP;
Summary of all metallurgical and metallurgical testing as required by
this Order or others of significance to the provisions of this Order;
Summary of the RCFA associated with the Houstonia 400 failure and
the Louisburg 100 failure and any others of significance to the
provisions of this Order;
Documentation of all actions taken by EPT/PEPL to implement the
IWP, or associated Appendices, or the consultant recommendations,
the results of those actions, and the inspection and repair criteria used;
Documentation of any revisions to the IWP or Appendices including
those necessary to incorporate the results of actions undertaken
pursuant to this Order whenever necessary to incorporate new
information obtained during the failure investigations, Consultant
recommendations, remedial actions or other elements under this Order;
Lessons learned while completing this Order;



20
10. 11. 12. 13. x. A path forward describing specific actions Respondent will take on its
entire pipeline system as a result of the lessons learned from work on
this Order; and
xi. Appendices as may be required.
It is requested that ETP/PEPL maintain documentation of the costs associated with
implementation of the Order, and include in each report submitted pursuant to Item 9,
the to-date total costs associated with: (1) preparation and revision of procedures,
studies and analyses; (2) physical changes to pipeline infrastructure, including repairs,
replacements and other modifications; and (3) environmental remediation, if
applicable.
The Director may grant an extension of time for compliance with any of the terms of
the Order upon a written request, timely submitted, demonstrating good cause for an
extension.
For all submissions based upon this Order that requires the approval of the Director,
the Director may (a) approve the submission in whole or in part; (b) impose specific
conditions; (c) modify the submission to cure any deficiencies; (d) reject the
submission in whole or in part; or (e) any combination of the above.
PEPL may appeal any decision of the Director to the Associate Administrator for
Pipeline Safety. Decisions of the Associate Administrator are final.
The above actions proposed to be required by this Notice of Proposed Safety Order are in
addition to and do not waive any requirements that apply to ETP/PEPL’s pipeline system under
49 C.F.R. Parts 190 through 199, under any other order issued to ETP/PEPL under authority of
49 U.S.C. Chapter 601, or under any other provision of Federal or State law.
After receiving and analyzing additional data in the course of this proceeding and
implementation of the work plan, PHMSA may identify other safety measures that need to be
taken. In that event, ETP/PEPL will be notified of any proposed additional measures and, if
necessary, amendments to the work plan or Safety Order.
___________________________________ December 22, 2014
Allan C. Beshore Date issued
Director, Central Region, OPS
Pipeline and Hazardous Materials Safety Administration



21
APPENDIX A
(A) (B) i. ii. (C) (D) i. ii. iii. iv. (E) (F) i. (G) i. ii. iii. Implementation of the -850 mV polarized potential criteria as defined in the Order
Directing Amendment (3-2010-1006M) to be completed.
Remediation of all known low potential areas as of the receipt of Order based on a
schedule provided to the Director and approved and reviewed by the Consultant. The
proposed schedule shall be received by the Central Region Director within 30 days of the
receipt of this Order.
This should include items discovered thru close interval survey (CIS), integrity
assessments or annual survey; and
Status of test station and rectifier repairs or CP system enhancements.
Correct all future identified low potential areas within 12-15 months regardless of
discovery method.
Identify rectifier performance and remediate areas of interference at a minimum by
completing the following:
Implement trends associated with current output for each rectifier on the system
but prioritized by LPA;
Develop and implement CP current management methods so that abnormal
current draw or use per line segment (whenever possible) can be identified;
Estimate current demand versus current availability; and
Identify areas of AC or DC interference.
Determine casing status and implement regular monitoring programs along with effective
remediation where needed.
Develop KPIs and performance measures for all elements of the corrosion control
program reviewed by the 3rd party expert.
A schedule regarding the prioritization and implementation of the KPIs and
performance measures will be provided to the Director.
Review and revise CP programs goals by completing the following:
Develop a structured, formal data integration process, for ILI data and CIS/LPA
matches and tie it directly to analysis and the formal remedial action plans;
Develop annual plan of activity and implementation;
Enhanced use of CIS and re-monitoring by CIS;



22
vi. Evaluate the CP status to see if/where a re-assessment is warranted.
(H) iv. Evaluation of coating quality especially Bucote as it relates to CGR;
v. Review of SOPs for pipe inspection to look for environmental factors, specifically
MIC as it relates to corrosion rates; and
Revise resource allocation and follow up activities and reporting by:
i. Install the means for a prioritization value to be entered in the electronic system
designed to track corrosion program activities. Design this prioritization
capability such that a priority value can be entered by any level of employee
involved in the decision making process including the level of employee
acquiring or entering the initial data.
(I) Implement bonded coupling program
i. Identify the location of unbonded or electrically discontinuous couplings.
ii. Implement a plan to bond or remove all couplings identified in item (I) i. that are
not addressed elsewhere in this Order within 10 years.



23
APPENDIX B
(A) (B) (C) i. (D) (E) (F) i. ii. iii. The Consultant should review and revise the ILI data (tool run) alignment process. This
process should provide automatic comparison of pipe diameter and wall thickness and
identify couplings and casing locations or other known asset features for location
confirmation of identified defects. This will also allow multiple ILI runs with different
tool technology or similar technology but with different vendor tools to be compared.
Field maintenance activities reports should be reviewed for tool data accuracy. This
project should result in all previous runs being compared prior to and after tool tolerance
is added.
The Consultant will establish procedures, which ETP/PEPL shall implement, to
determine conservative corrosion growth rates. If verified data acceptable to the
Consultant is not present, the corrosion growth rate per NACE SP502 standard (16 mpy)
shall be utilized.
The Consultant shall evaluate the implementation and performance of the risk evaluation
using this new system process and shall include preventative and mitigative measures and
the substantiation of adequate corrosion growth rates.
Provide Integrity Summary Reports for all segments of pipeline.
The Consultant shall establish conservative feature interaction rules for use by the ILI
tool vendor and ETP/PEPL.
The Consultant shall establish ETP/PEPL procedures to determine the most conservative
(lowest predicted failure pressure) equation which will be used to calculate the predicted
failure pressure (B31G, modified B31G, RSTRNG) to identify anomalies for remediation
and repair.
ETP/PEPL shall enhance engineering processes and evaluation of ILI data by completing
the following:
Implement tool vendor processing of data and calculation of FPR;
Compare tool vendor data analysis and calculation process to that of the
ETP/PEPL;
Implement procedures that statistically determine the number of required
confirmation digs to substantiate tool reporting accuracy. This should be done in
a method to establish 95% statistical confidence, utilize unity plots, and account
for changes in tool specification criteria based on varying defect morphologies
(length and depth) and interaction of features;



24
(G) (H) (I) (J) (K) (L) (M) (N) iv. Implement a procedure that collects all necessary field information (field
measurements associated with dig sites, any mag. particle or metallurgical
findings) to allow analysis of tool performance;
v. ILI data will be evaluated using dig results and adjustments to the data will be
made based on tool related variances; and
vi. Generate unity plots.
The IWP for the ETP/PEPL System must fully address all known or suspected factors per
pipeline that have caused or contributed to the previous incidents, or have been
discovered as lessons learned. This should include a review of reportable and non-
reportable DOT events. The review of ETP failures (such as FGT) will be included.
Data-gathering activities must include a review of the failure history (in-service and
pressure test failures) of the entire length of the ETP/PEPL System since 2000 and the
development of a written report containing all available information regarding locations,
dates, pipeline name and causes of failures.
The Consultant shall review all current pressure reductions resulting from integrity
concerns by location and line. A report shall be prepared for PHMSA as a result of the
Consultant review that lists the magnitude of the current pressure reduction by location,
relevant remote or local alarm limits, software programming set-points or control points,
and mechanical over-pressure devices, pressure regulator and ESD set points.
Provide a summary of all locations that have experienced SCC or Flash weld associated
seam corrosion by pipeline name and location. Submit to PHMSA an engineering
summary that identifies why similar areas with SCC or Flash weld associated seam
corrosion cracking on adjacent ETP/PEPL pipelines are not experiencing similar threats.
(For example, if SCC has been determined to exist on the 300 line and preventative
measures are in place, identify why from an engineering perspective the 400 line in this
same area is not susceptible.) Explain in this engineering summary how the retest
intervals are being established and implemented.
Provide a review and identify an improvement plan to remediate or remove all couplings
not previously addressed by other sections in this Order.
Review near neutral SCC procedures.
The Consultant shall review and revise as necessary MIC and AC/DC interference
procedures and remediation actions.
Evaluate existing anomaly response criteria. Include in the evaluation of response criteria
a review of repair and remediation efforts that are prioritized (HCA, Class, and SRCR
shall be required as a minimum).
Review headquarter and field responsibilities and resources - training, allocation,
deployment of skill sets.



(O) 25
Review safety related condition reporting processes to determine if improvements or
enhancements are needed.



26
APPENDIX C:
(A) i. (B) i. ii. iii. (C) i. ii. iii. iv. Enhanced Safety and Integrity Culture through Reporting, Learning and Training
Review ETP/PEPL expansion or enhance efforts regarding the existing
ETP/PEPL safety culture program and processes, placing an emphasis on
pipeline integrity and corrosion control. Review the application of the existing
processes within the Impact Safety management system to identify, report, and
manage unwanted events. Review how the existing system can be utilized to
encourage continuous improvement and a learning culture.
Reporting criteria for additional unwanted events and issues
Review action item and learning process workflow;
Review management of change process workflow; and
Review the development of KPIs and performance measures indicative of
corrosion control and pipeline integrity process performance.
In consideration of process and procedure improvements resulting from the recent
ETP/PEPL incident history and RCFAs, review processes to proactively manage the subject
improvements and assure a formal MOC process occurs. Review the development and
implementation of training and communication programs to assure people, process and
technology components are fully implemented across the enterprise and changes are
institutionalized accordingly including:
Review updates of SOPs and integrity management program documents;
Review the training field technicians and SMEs in Corrosion Control and
Integrity Management procedural/program changes;
Review training and communication to technical support and management
personnel related to changes in work management and management of KPIs; and
Review processes and program design to verify that ongoing attention to key
focus areas, such as integrity programs and corrosion control systems, is
maintained during outside influences including organizational changes, mergers,
acquisitions, resource changes, retirements, new hires, etc. and work to assure
that any changes are managed so that safety performance is not negatively
impacted.



27
APPENDIX D:
(A) The plan needs to address utilizing Geographic Information Systems and related
applications to manage the following data and any other integrity related information:
i. HCAs
ii. Class locations
iii. Common corridors
a. Including type identification (type of corridor)
iv. Age and year of installation in combination with pipeline specifics (diameter,
SMYS, wall thickness, coating type, cathodic protection date)
v. Structures within a 1000 feet
vi. Runways
vii. Test stations
viii. Bonds
ix. Rectifier and ground beds
x. Foreign line crossings
xi. Casings with shorted casings identified
xii. Repairs (including temporary repairs)
xiii. Reinforced and unreinforced couplings (project status)
xiv. Pressure reduction locations and reason for the reduction
xv. Areas not capable of accommodating smart pigging
xvi. All pipeline replacements
xvii. All areas of SCC or Crevice corrosion
xviii. Areas that have not been hydrotested since original construction.
xix. Locations of all failures and leaks including hydrotests
xx. CIS locations



28
xxi. Low potential areas
xxii. Spans and pipe exposures
xxiii. Areas of high potential as identified by procedure modifications
xxiv. Areas operating at over 72% SMYS
xxv. Recoated project areas
xxvi. Abandoned or inactive pipe locations
xxvii. Areas subject to the influence of stray current (power lines, wind farms, etc.)
xxviii. PIRs
(B) ETP to enhance and integrate these data collection efforts into the corrosion threat
management processes.
i. ILI and CIS Data Alignment
(C) Automated data entry and analysis opportunities (Forms of various types)
i. Opportunities captured from review of current IMP and CP

## Provenance

- Official: Yes
- Source: <https://primis.phmsa.dot.gov/enforcement-data/case/320141008S>
- Source ID: `phmsa-enforcement`
- SHA-256: `943e8ce5c156608a93a0632ea81ef07041c894f18e424c0813c2a8f2c4f2f829`
- Retrieved: 2026-08-20T04:44:44.458Z
- Exported: 2026-08-23T04:34:26.202Z
- Document slug: `phmsa-enforcement-320141008s`

### Source metadata

```json
{
  "cpf": "320141008S",
  "operator": "PANHANDLE EASTERN PIPELINE CO",
  "region": "Central",
  "pipelineType": "GAS INTERSTATE ONSHORE",
  "caseStatus": "CLOSED",
  "citedSections": [],
  "dataAsOf": "08/04/2026 12PM",
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  "jurisdiction": "US",
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}
```