Before the
U.S. Department of Transportation
Pipeline and Hazardous Materials Safety Administration
Office of Pipeline Safety

In the Matter of
ExxonMobil Pipeline Company
Pegasus Pipeline incident
(March 29, 2013), Mayflower, Arkansas

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CPF No. 4-2013-5027
Notice of Probable Violation

RESPONDENT’S
PRE-HEARING BRIEF

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I.

INTRODUCTION

On March 29, 2013, the Pegasus Pipeline, a 20” diameter pipe carrying crude oil ruptured near
Mayflower, Arkansas. The pipeline is owned by Mobil Pipe Line Company, and operated by the
ExxonMobil Pipeline Company (EMPCo or the Company). The pipeline was constructed in
1947-1948 and maintained under regulations promulgated by the federal Pipeline and Hazardous
Materials Safety Administration (PHMSA or the Agency). The Company conducted hydrostatic
pressure tests of the line at the time of construction, in 1969, 1991 and again in 2005-2006. The
Company also conducted in-line inspections (ILI) of the pipe multiple times, from 1999 to 2001,
again in 2010, and again from 2012 to 2013. Hydrotests and ILI are conducted to detect
anomalies that could lead to failure if not remediated, but no such anomaly was ever found or
reported at the point of the Mayflower rupture prior to the incident.
PHMSA issued a Notice of Probable Violation, Proposed Penalty and Proposed Compliance
Order (collectively, the NOPV) to EMPCo on November 6, 2013. The NOPV set forth nine
alleged violations of the Agency’s integrity management program (IMP) rules, and proposed a
civil penalty in excess of $2.6 million dollars and a broad compliance order. The Company
contested the allegations and requested an administrative hearing on the NOPV.
The federal Pipeline Safety Act (PSA) and PHMSA’s regulations implementing that statute
establish a set of performance-based regulations that require pipeline operators to create their
own written programs, specific to the pipeline at issue. Under the IMP rules, operators are
required to prepare a written IMP plan, create a Baseline Assessment Plan (BAP), establish a
schedule for hydrotest and/or ILI assessment, and, where appropriate, develop risk reduction or
remediation strategies. EMPCo fully complied with the IMP rules for this line. In fact, the
Company conducted more inspections of the line and implemented more risk reduction measures
than are required by the regulations.
The PSA does not create a strict liability scheme, meaning that the occurrence of an incident
does not automatically give rise to a violation of PHMSA regulations. In this case, PHMSA has
alleged violations as if strict liability did apply; the NOPV presumes violations simply because
an incident occurred. The PSA and its implementing regulations make clear that such an
approach is not consistent with the applicable law. Pipeline operators, and the Agency, are
expected to continually improve IMP programs as new information and new technology become
available, to find and correct violations when they occur, and also to learn from incidents even
where no violations exist, in order to reduce the likelihood of recurrence.
As the evidence will show, the Company complied with all applicable regulations in this
instance. The anomaly that caused the Mayflower incident was not detected prior to the incident
using recognized industry best practices. Accidents can occur even when an operator is in full
compliance with applicable law. The PSA and its regulations acknowledge that fact, but the
NOPV ignores it.
This challenge to the NOPV is not about monetary fines. The Company has already paid many
millions of dollars in response to the Mayflower incident. This challenge is about the proper
interpretation of the PSA, and ultimately about the proper focus in learning from an incident and
working to improve pipeline integrity and public safety.
The Agency should withdraw or revise the NOPV as issued.  
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II.

BACKGROUND
A.

The Pegasus Pipeline System and the Mayflower Incident

The Pegasus Pipeline System consists of 859 miles of predominately 20” pipeline that transports
Canadian heavy crude oil originating from Patoka, Illinois to Nederland, Texas, at which point
the product is provided to Gulf Coast refineries and export marine facilities. The entire line was
shut down in 2002 for market reasons, and was then reversed and restarted in 2005-2006. The
system has a capacity of approximately 90,000 barrels per day and was operated at a MOP of
820 psi that was established through a 2006 hydrotest.
The system is comprised of three distinct pipeline segments that were constructed separately,
with different metallurgy, manufacturer, and/or manufacturing methods, and that have been
subject to different operating histories over the years. The segment at issue in this NOPV runs
from Patoka, Illinois to Corsicana, Texas and was constructed in 1947-1948 from predominantly
Youngstown 20” X-42/electric resistance weld (ERW) pipe, as well as some seamless pipe. See
Figure 1: Pegasus Pipeline System.
Figure 1: Pegasus Pipeline System

 

On March 29, 2013, at 2:37 p.m. Central Standard Time (CST), a drop in pressure was detected
in the Conway to Corsicana line segment by EMPCo’s Operations Control Center in Houston,
Texas. Following receipt of a low pressure alarm (32 psig) and a pressure rate of change alarm
(negative drop of 668 psig), the OCC controller began initiation of a full safe shutdown of the
pipeline, which included a carefully staged shutdown of all pumps along the entire length of the
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pipeline and full isolation of the section of the pipeline where the release was located by closing
mainline valves upstream and downstream of the rupture site. As a result, EMPCo detected the
potential release, confirmed it was an actual release, and shutdown and completely isolated the
affected segment within 16 minutes of the rupture.
The pressure drop resulted from a rupture of the pipeline at Milepost 314.77, causing a release of
crude oil near Mayflower, Arkansas. At the time of failure, the pressure at the release site was
estimated to be approximately 703 psi (below the release site MOP of 863 psi). EMPCo reported
the release to the National Response Center on March 29, 2013, at approximately 3 p.m. CST
(NRC Report No. 1042466), estimating that between 3,500-5,000 barrels of crude oil had been
released. On April 8, 2013, EMPCo revised that estimate to 5,000 barrels.
EMPCo immediately initiated response efforts, in coordination with PHMSA, U.S. EPA, local
police and other State and local agencies. The release occurred in a residential neighborhood and
twenty-two homes were evacuated as part of the Company’s response efforts. No injuries,
fatalities or fires occurred. While the oil flowed into storm drains leading to nearby Lake
Conway, a local fishing spot, no oil is believed to have reached the main body of the lake. To
date, the Company has expended more than $75 million in response related costs. The line has
not yet been put back in service. 
B.

PHMSA Initial Administrative Action

PHMSA issued a Corrective Action Order (CAO) to EMPCo on April 2, 2013, just three days
after the release occurred. The CAO imposed four major corrective actions on the entire Pegasus
Pipeline: metallurgical testing, preparation of a remedial work plan and a Restart Plan, and a
pressure restriction. EMPCo requested a Hearing on the CAO, seeking to clarify or modify the
Order with respect to the following: (1) the restart pressure restriction at the failure location; (2)
the extent of the system subject to the CAO and the hazardous facility determination; and (3)
restart pressure restrictions at other stations along the pipeline. Following the Hearing on May 2,
2013, PHMSA issued a Final Order on May 10, 2013, agreeing to amend the CAO to address the
pressure issues and acknowledging that the scope of the CAO could be limited in the future
depending on the results of further investigation.
C.

Root Cause Failure Analysis and Re-Start Plan

The Root Cause Failure Analysis (RCFA) that EMPCo submitted to PHMSA on April 15, 2014,
concluded that the failure was caused by original manufacturing defects, namely hook cracks
along material imperfections in steel on the long seam. Exhibit 56, EMPCo Pegasus RCFA
Final Report, p. 2 (Mar. 26, 2014). The initial defects grew in service, over time, to critical flaw
size, which resulted in the rupture. Metallurgical testing conducted by HurstLab concluded that
the failure occurred:
because of the reduction of the wall thickness in the upset zone of the Electric Resistance
Weld (ERW) seam caused by the presence of manufacturing defects, namely the
upturned bands of brittle martensite, combined with localized stress concentrations at the
tips of the hook cracks, low fracture toughness of the material in the upset/HAZ,
excessive residual stresses in the pipe from the initial forming and seam and girth
welding processes, and the internal pressure creating hoop stresses.
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Exhibit 55, Hurst Metallurgical Report No. 64961, p. 31 (rev. July 9, 2013). With respect to
other contributing or likely contributing factors, EMPCo and industry expert John Kiefner who
provided input on the RCFA identified atypical pipe properties that contributed to accelerating
the propagation of cracks and the failure (e.g., very high tensile strength, local high hardness,
high carbon and manganese content, brittle fracture mode, residual stresses).
Exhibit 56,
Appendix 3 to EMPCo Pegasus RCFA Final Report prepared by Kiefner & Associates; see also
Exhibit 1, Kiefner Affidavit ¶¶ 16-17, 24 (noting that the Pegasus Pipeline “exhibited highly
unusual chemical and mechanical properties,” “the characteristics of the pipe at the particular
point of failure were unique,” and that “the anomaly that caused the Pegasus incident was not
capable of reliable detection give that it exhibited atypical characteristics not frequently seen
before in the industry”).
As required by the CAO, EMPCo continues to work with PHMSA to develop approved Re-Start
Plans (RSP) for the pipeline. 1 A RSP for the portion of the line between Corsicana and
Nederland, Texas was submitted to the Agency on January 31, 2014. The RSP was approved by
the Agency on March 31, 2014 and plans are underway to initiate restart. The Company
continues to finalize its RSP plan for the Patoka to Corsicana portion of the line before
submitting it to PHMSA.
D.

Issuance of NOPV, Proposed Penalty and Compliance Order by PHMSA

PHMSA issued the NOPV to EMPCo on November 6, 2013, including nine (9) Items of alleged
violation, proposing more than $2.6 million in civil penalties and proposing a Compliance Order.
Eight of the nine alleged violations cite to PHMSA’s IMP regulations at 49 C.F.R. Part 195.452.
One of the alleged violations invokes Part 195.402 (concerning Operation & Maintenance
Manual requirements) but that Item also directly relates to IMP. All of the alleged violations are
associated with a proposed penalty. Five (5) of the alleged violations (Items 1, 2, 5, 6 and 8) are
related to the Proposed Compliance Order (PCO). EMPCo timely requested a hearing on
December 6, 2013, pursuant to PHMSA regulations at 49 C.F.R. Part 190. The Hearing is
scheduled for June 11, 2014.2

                                                            
1

Additionally, in compliance with the CAO, the Company submitted Remedial Work Plans (RWP) to PHMSA for
both the Corsicana to Nederland, Texas portion of the pipeline and the Patoka, Illinois to Corsicana, Texas portion.
EMPCo continues to work with the Agency to finalize the RWPs.

2

Following the issuance of the NOPV, EMPCo requested and received on November 21, 2013, a copy of PHMSA’s
“Pipeline Safety Violation Report”(PSVR) (dated Nov. 6, 2013), and a copy of PHMSA’s “Mayflower Failure
Investigation Report” (dated Oct. 23, 2013). Neither of these documents are referred to or incorporated into the
Agency’s NOPV, but they provide information relied upon by PHMSA in preparing its claims in the NOPV. The
documents, both of which are lengthy, contain incorrect factual information and unsupported legal conclusions that
go beyond the allegations set forth in the NOPV. To the extent any such information or conclusions are relevant and
material to the claims presented in the NOPV, EMPCo addresses it in its Request for Hearing pleadings (including
this Brief). The Company is not addressing the entirety of the PSVR or Accident Report in this proceeding,
however, and the Company denies any and all factual or legal conclusions contained in those documents.

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III.

APPLICABLE LAW
A.

There is No Strict Liability under the PSA

It is evident that the government believes that simply because an incident occurred in this matter,
then EMPCo must have violated the Part 195 regulations. The legal concept of strict liability
supports such an approach, but it is not available here. Where strict liability does apply, an entity
may be liable solely because of the occurrence of an event, without consideration of fault or
cause.3 The federal PSA has no such strict liability provision. There is nothing in the statute or
PHMSA regulations implementing the statute that establishes liability for a pipeline incident
without fault.
The Agency’s regulations instead establish a series of performance based standards, which often
incorporate various technical standards and methods. This performance based scheme is
intended to provide operators with flexibility to select the most effective processes and
technologies based on their specific pipeline characteristics.4 Pipeline operators are required to
follow the procedures established in this regulatory framework, and document all relevant
considerations and actions taken.
Although many pipeline accidents are associated with underlying violations of PHMSA
regulations (e.g., operator error, failure to maintain specified records, insufficient cathodic
protection, etc.), some incidents occur despite an operator’s compliance with all applicable
regulations. See Exhibit 2, Muhlbauer Affidavit ¶ 13 (noting that “[d]ue to the probabilistic
nature of such scenarios, incidents can occur despite significant efforts to prevent them”). This
is one such incident. Unfortunately, whether influenced by media attention or political pressure,
agencies are sometimes inclined to presume violations simply because an incident occurred. The
law does not support such an approach. The Agency must prove, as a matter of law, that a
violation of its regulations occurred to support each of the nine items in the NOPV in this case. 
B.

Overview of Integrity Management Rules

When promulgating the integrity management regulations at 49 C.F.R. Part 195.452, PHMSA
increased its emphasis on performance based risk management regulations. More so than any
other regulations under Part 195, the integrity management rules are process oriented and allow
operators a high degree of flexibility to adapt their programs and plans to fit particular
circumstances. Final Rule, 65 Fed. Reg. 75378, 75382 (Dec. 1, 2000) (“Performance based
language will best achieve effective integrity management programs that are sufficiently flexible
                                                            
3

An example of such a provision is found at Section 301 of the federal Clean Water Act (known as ‘the discharge
prohibition’), where any unpermitted release of oil to waters of the U.S. creates liability regardless of how or why
the release occurred. 33 U.S.C. §§ 1311(a), as implemented through 33 U.S.C. §1321(b)(6)(A) (authorizing
assessment of administrative penalties to any “owner, operator, or person in charge” of a vessel, onshore or offshore
facility from which oil is discharged); 1321(f) (creating liability for removal costs up to finite amounts for such
owners or operators and providing for increased liability where the government can show willful negligence or
willful misconduct).
4

In promulgating the original 1969 liquid pipeline regulations, which were the blueprint for the current regulations
at Part 195, DOT’s Hazardous Materials Regulations Board emphasized performance over prescriptive standards for
the purpose of encouraging industry innovation and technological improvements. See e.g., Final Rule, 34 Fed. Reg.
15473, 15474 (Oct. 4, 1969).

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to reflect pipeline specific conditions and risks. Performance based standards allow an operator
to select the most effective processes and technologies as they become available.”).
Under these rules, which first became effective in 2001, operators were required to develop a
written IMP plan that included the following: (1) identification of pipelines that could affect
sensitive areas called high consequence areas (HCAs); (2) a baseline assessment plan (BAP) for
initial assessments of those lines; (3) procedures for the integration of all available information
about pipeline integrity and the consequences of a failure; (4) prompt action to address issues
identified by the assessment and prioritization of repairs; (5) reassessment at least every five
years; (6) continual evaluation to include additional preventive and mitigative measures as
appropriate; (7) methods to measure effectiveness; and (8) a process for review of the assessment
results by a qualified individual. 49 C.F.R. Part 195.452(f); see Figure 2: IMP Program
Elements.
Figure 2: IMP Program Elements, 49 CFR Part 195.452(f)

 

While the rule prescribes which program components are required, its performance based
elements allow operators discretion in how to implement these components. For that reason,
PHMSA anticipated that this would be an evolving “dynamic” iterative process for both
operators and the industry, and the agency continues to emphasize that point. Final Rule, 65
Fed. Reg. 75378, 75386 (Dec. 1, 2000); see also PHMSA Advisory, 79 Fed. Reg. 25900, 25993
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(May 6, 2014) (“Continual improvement of IM programs (including improvements in the
analytical processes involved in analyzing assessment results, identifying threats, responding to
risks, the application and implementation of assessments and the development of preventative
and mitigative measures) is a key aspect and critical objective of an effective IM program.”). As
recent statistics confirm, the performance-based integrity management rules have been
successful in improving pipeline safety. Since the liquid IM regulations became effective in
2001, liquid pipeline incidents have decreased by 62%, the amount released by liquid pipelines
has decreased by 47%, and liquid incidents that resulted from material defects, seam and weld
failures decreased 31%. Annual Liquid Pipeline Safety Performance Report & Strategic Plan,
prepared by AOPL and API, p. 15 (2013).
C.

Threat Identification and Risk Assessment under IMP

A primary component of IMP is the operator’s threat identification and risk assessment process
which informs both the integrity assessment schedule and its method under certain
circumstances. 49 C.F.R. Parts 195.452(e); 195.452(j)(5). The Agency requires operators to
evaluate numerous risk factors for each pipeline segment, including the results of prior
assessments, manufacturing information and seam type, among other factors. 49 C.F.R. Part
195.452(e). Based upon the results of that analysis, an operator must prioritize its segments for
reassessment on a five year interval. 49 C.F.R. Part 195.452(j)(3). Consistent with the intent of
the IMP regulations, operators are required to consider all of the regulatory risk factors in
developing their assessment schedule, but they have discretion in determining the weight and
risk score given to each factor and prioritization for a particular pipeline system. See e.g., In re
Magellan Midstream Partners, CPF No 4-2006-5020 (July 9, 2009).
The IMP rules set forth three assessment methods available to operators: (1) inline inspection or
ILI; (2) hydrostatic pressure testing; and (3) external corrosion direct assessment. 49 C.F.R.
195.452(j)(5). For low frequency ERW (LF-ERW) or lap welded pipe that is susceptible to
longitudinal seam failure, the assessment method “must be capable of assessing seam integrity
and of detecting corrosion and deformation anomalies.” Id. PHMSA guidance clarifies that
these methods include an ILI device capable of detecting seam flaws, metal loss corrosion, and
deformation anomalies, or a hydrostatic test. PHMSA Hazardous Liquid FAQ 6.10. In addition,
PHMSA guidance clarifies that evaluation of seam susceptibility “can involve a variety of
factors such as original pipe purchase specifications, incident history, operating pressure, prior
pressure testing, pressure cycling, etc.” PHMSA Hazardous Liquid FAQ 6.11(a). PHMSA
guidance also notes that a process should be in place to reevaluate this determination on an
appropriate interval if any factors have the potential to change. Id. Beyond this, PHMSA has
not promulgated any additional requirements or guidance associated with integrity management
requirements for LF-ERW pipe.
An Agency-commissioned report was released in 2004 to address how an operator should assess
whether LF-ERW pipe is susceptible to seam failure. See Michael Baker and John Kiefner, Low
Frequency ERW and Lap Welded Longitudinal Seam Evaluation (2004) (Baker/Kiefner Report).
This report was largely based on a 2002 report issued by Kiefner, entitled Dealing with Low
Frequency Welded and Flash Welded Pipe with Respect to HCA Related Integrity Assessments
(2002). While the evaluative process described in these reports is not incorporated into the
regulations, it has been endorsed by the Agency through subsequent enforcement and referenced

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in the Agency’s enforcement manual. 5 Specifically, the process considers pipe and seam
characteristics, in service and hydrostatic test failures, the cause of those failures, operating stress
level, fracture toughness, fatigue crack growth rate characteristics and the nature of operational
pressure cycles on the pipeline. This data is then applied to determine whether a given segment
of LF-ERW pipe is susceptible to seam failure. Id. at p. 18 (Figure 4.1.);6 see also Exhibit 3,
Baker/Kiefner Report Figure 4.1.
For the reasons noted above, and contrary to PHMSA’s assertions in the NOPV and Pipeline
Safety Violation Report (PSVR), all LF-ERW pipe is not presumptively susceptible to seam
failure. PHMSA law and guidance requires consideration of seam failure susceptibility, but it
does not require a presumptive conclusion of susceptibility where the pipeline has been subjected
to a hydrostatic test and an engineering analysis indicates that there is no evidence of pressure
cycle fatigue, preferential seam corrosion, or other time dependent defects.
D.

Discovery, Mitigation and Risk Reduction

After carrying out an integrity assessment, PHMSA regulations require that operators validate
the results of an integrity assessment, account for ILI tool tolerances, and integrate all available
data regarding the pipeline. 49 C.F.R. Part 195.452(g); PHMSA Hazardous Liquid IMP FAQ
7.19 (“tool tolerance should be considered as part of the data integration process” as well as prior
excavations, digs, and inspections). Factoring in that analysis, operators “discover” integrity
conditions when they have adequate information about the condition to determine whether an
anomaly exceeds the criteria established in the IMP regulations. 49 C.F.R. Part 195.452(h)(2).7
This must occur promptly, but no later than 180 days after an assessment unless that period is
impracticable, allowing for flexibility because discovery varies depending on the circumstances.
Final Rule, 65 Fed. Reg. 75378, 75384 (Dec. 1, 2000) (noting that discovery may occur when an
operator receives the preliminary ILI report, gathers and integrates information from other
inspections or periodic evaluations, excavates the anomaly or receives the final internal
inspection report); see also PHMSA Hazardous Liquid IM FAQ 7.3.
Once operators declare discovery, they must timely remediate and repair integrity conditions that
exceed regulatory criteria based on a prioritized schedule. 49 C.F.R. Part 195.452(h)(3)-(4).
While some conditions require immediate repair, others must be scheduled within 60 days of
                                                            
5

In re Kinder Morgan Energy Partners, CPF No. 1-2004-5004 (June 26, 2006) (noting that Kiefner’s methodology
is an example of an acceptable means of performing a seam failure susceptibility analysis); see also PHMSA
Hazardous Liquid IM Enforcement Guidance p. 131 (Sept. 17, 2013).

6

Notably the Baker/Kiefner Report explains that Figure 4.1 “represents a decision tree that allows one, by supplying
appropriate data on a given segment, to determine if a seam-integrity assessment is required based on the federal
pipeline integrity management regulations” and that “baseline assessment in the form of a hydrostatic test
demonstrates a level of serviceability consistent with the test-pressure to operating pressure ratio the operator
selects. Additional information may be derived from the examination of test leaks or breaks if any occur.
Remaining life after the test can be assessed from the standpoint of pressure-cycle induced fatigue. The results of
the test are expected to provide sufficient information for the operator to decide whether or not the pipeline is
susceptible to seam failure in the context of the federal regulations pertaining to pipeline integrity management (49
C.F.R. 195.452).” Baker/Kiefner Report, pp. 16-17 footnote 3 (emphasis added).
7

PHMSA guidance clarifies that where tool run data is suspect and an entire rerun is performed, the evaluation will
be expected within 180 days of the successful tool run. PHMSA Hazardous Liquid IMP FAQ 4.13.

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discovery, 180 days, or later under certain circumstances. 49 C.F.R. Part 195.452(h)(4).
PHMSA guidance clarifies that “immediate” repair means that repairs must be effectuated “as
soon as practicable.” PHMSA Hazardous Liquid FAQ 7.4.
In addition to performing required repairs, operators must conduct a risk analysis regarding
whether additional preventive and mitigative (P&M) measures are warranted to mitigate the
consequences of a failure that could affect an HCA. 49 C.F.R. Part 195.452(i) (evaluating the
likelihood of a pipeline release and how it could affect the HCA based on all relevant risk
factors). Specific P&M measures mentioned in the regulations include establishing shorter
inspection intervals and installing emergency flow restrictive devices (EFRDs), among others.
49 C.F.R. Part 195.452(i)(1). There is, however, no regulatory timeframe associated with
implementing P&M measures, and PHMSA has acknowledged that this time period is highly
dependent on the proposed P&M measure, noting that while some measures can be implemented
quickly, others require significant time for budgeting, engineering and design. PHMSA
Hazardous Liquid IMP FAQ 9.9 (“because of this wide disparity, there is no fixed time
requirement for implementing preventive and mitigative actions”).
IV.

NOPV ITEM BY ITEM ARGUMENT

The issues as joined in this proceeding present questions of law under the Pipeline Safety Act
and its implementing regulations at 49 C.F.R. Part 195. The NOPV contains nine claims of
alleged violation of law. The Respondent’s Request for Hearing contests each of those
allegations, asserting that it is possible for pipeline accidents to occur even when an operator is
in compliance with the applicable law.
The material facts of the incident, and actions leading up to the incident, are largely undisputed.
For the majority of the NOPV Items (Items 1 – 4, 7 and 8), there is no issue of material fact. For
those Items, the only potential questions of mixed law and fact can be summarized as follows:
(1) did the Company conduct a risk assessment that considered LF-ERW seam failure
susceptibility, as required by Part 195.452(e)?
(2) did the Company conduct a risk ranking of the pipe segment at issue, as required by
Part 195.452(j)(2)?
(3) were the various tools and inspection methods that were employed prior to the
incident, as required by Part 195.452(j)(5), designed to reliably detect the anomaly that
existed?
As the record reflects that the answer to the above questions is in the affirmative, but the Agency
has not provided adequate reasoning to justify its approach to these questions. As the record and
exhibits establish, the Company did conduct a risk assessment that considered the risk of seam
failure, as well as appropriate risk ranking using all available information. The record also
shows that the anomaly at the point of rupture was not detected by the multiple inspection
methods and tools employed prior to the incident.
The remaining allegations in NOPV Items 5, 6 and 9 are based upon mistakes of fact, as is
demonstrated by record evidence, and therefore cannot be sustained. With all of these factual
issues clearly established by the record, only legal questions remain, all relating to the proper
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implementation of the Agency’s authority under the PSA and the application of the plain
language of its regulations.
NOPV ITEM 1: Alleged Failure to Consider Risk of Seam Failure on ERW Pipe
In Item 1 of the NOPV the Agency alleges that the Company did not consider seam failure
susceptibility as a risk factor in its IMP program as required by 49 C.F.R. Part 195.452(e)(1).
The record clearly shows that the Company did expressly consider seam failure susceptibility for
ERW pipe and documented those analyses. Thus, although not stated as such, the NOPV is
actually alleging that the Company violated the IMP requirements by not concluding that the
pipe was susceptible to seam failure.
This distinction in how the NOPV is drafted is significant. The Agency’s IMP regulations do not
dictate the conclusion that an operator should reach in following the threat identification and risk
assessment process required by Part 195. To the contrary, the regulations require only that an
operator fully consider all applicable threats, and document that process. EMPCo did just that.
The fact that the Company did not conclude that the pipe was susceptible to seam failure does
not give rise to a violation of applicable law.
Roughly one-fourth of all oil pipelines in the U.S. are LF-ERW.8 The Agency’s approach to
consideration of LF-ERW pipe as stated in the NOPV does not follow PHMSA’s own rules or
precedent. As articulated in this proceeding, PHMSA’s approach to LF-ERW pipe would have a
significant adverse impact on public safety and energy transportation.
Initial Seam Failure Analyses and Integrity Assessment
EMPCo’s written IMP Baseline Assessment Plan was first prepared in 2001 and its IMP plan
was finalized in 2002, in close consultation with leading industry experts, such as John Kiefner
and Kent Muhlbauer. Exhibit 1, Kiefner Affidavit ¶ 10; Exhibit 2, Muhlbauer Affidavit ¶ 6. The
IMP plan has been reviewed annually and updated over time (with continuing input from Kiefner
and Muhlbauer), to reflect changes in the regulations, and to incorporate industry guidance and
lessons learned from operation of the EMPCo system. Id.; see also Exhibit 2, Muhlbauer
Affidavit ¶ 7 (noting that EMPCo’s IMP manual “is among the most complete and well-written
of any such manuals I have seen”). The Company’s IMP program has also been reviewed by
PHMSA on multiple occasions (2003, 2007 and 2011), including an in-depth review of the
Pegasus system specifically in 2007. The Company addressed all concerns noted by the Agency
in those reviews, through further revisions to its IMP plan.9   
                                                            
8

PHMSA, Hazardous Liquids Annual Data 2012 (as of May 1, 2014) available at www.phmsa.dot.gov, (as set forth
in annual operator reports submitted in 2013 for the year 2012 and including direct current welded pipe).
9

As a result of the Agency’s 2011 inspection, PHMSA cited EMPCo for violations of Part 195 for which a Petition
for Reconsideration is pending. PHMSA Final Order, CPF No. 4-2011-5016 (June 27, 2013). As part of that
action, PHMSA issued a Compliance Order with two items. Item 1 of the Compliance Order has been stayed
pending a decision on the Petition, and EMPCo timely submitted revised procedures under Item 2 of the Compliance
Order to the Southwest Region on August 1, 2013. PHMSA Inspector John Pepper responded to the proposed
revisions requesting additional modifications on August 5, 2013; EMPCO addressed those in a further revised
version submitted to PHMSA on August 29, 2013. To date, the Company has not heard back from PHMSA on
those revisions or its Petition for Reconsideration.

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In compliance with the above regulatory requirements and guidance, EMPCo developed a
process for analyzing seam failure susceptibility in reliance on the Kiefner and Baker Reports10
and in consultation with Kiefner himself. Exhibit 1, Kiefner Affidavit, p. 2 ¶¶ 11-12. Kiefner
created the Pipelife software for the industry at the request of EMPCo to use in analyzing
pressure cycling induced fatigue. Id. The results of this analysis were expressly considered in
EMPCo’s Threat Identification and Risk Assessment (TIARA) software inputs, which identify
IMP threats and the relevant risk score of a pipeline segment. Exhibit 13, EMPCo TIARA
Foreman to Conway UDT Q&A (6/26/06). All results were then considered in developing
reassessment schedules.
EMPCo first evaluated the pipeline’s susceptibility to longitudinal seam failure in late 2004 and
early 2005, as the Pipelife software and Baker Report became available. Exhibit 8, EMPCo
Memo regarding Corsicana to Patoka LSFSA (Dec. 10, 2004); Exhibit 9, Memo regarding
Corsicana to Patoka LSFSA (Feb. 10, 2005); see Figure 3 EMPCo IMP Assessment and LSFSA:
Conway to Foreman. The Company’s 2004-2005 evaluations of the Pegasus Pipeline included
consideration of pressure cycling induced fatigue and concluded that the pipe was not susceptible
to seam failure. Id. Because the line had been idled from 2002-2005, the Company conducted a
baseline assessment hydrostatic test in 2005-2006. Following the process developed by Kiefner
and reflected in the Baker Report, the failures that occurred during the hydrotest were
subsequently repaired and analyzed by an expert metallurgist for evidence of pressure cycling
induced fatigue and preferential seam corrosion. Exhibits 12 and 15, EMPCo Excerpts of
Metallurgical Analyses performed by HurstLabs (2006); Exhibit 14, EMPCo Corsicana to
Patoka Summary of Hydrotest Learnings (July 6, 2007). The results of those analyses did not
indicate the presence of either condition. Id.

                                                            
10

EMPCo has reviewed and updated this process numerous times since its inception, including incorporating
updated versions of the Pipelife software, revising the LSFSA analysis, sharing metallurgical findings with Kiefner
and Associates in support of industry studies, performing a companywide fatigue screening for all LF-ERW
pipelines, and developing a SCADA-based system to detect pressure cycling tends with the potential to shorten the
theoretical fatigue lives, among other updates.

12
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Figure 3
EMPCo Integrity Assessment and LSFSA Analysis: Conway to Foreman
(prior to March 29, 2013 Mayflower Incident at MP 314.77)

13
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In planning the next integrity reassessment for 2010, the Company’s TIARA software accounted
for the seam type, history and the long seam failure susceptibility analysis (LSFSA), among
other inputs. Exhibit 13, EMPCo TIARA Foreman to Conway UDT Q&A (June 26, 2006).
Again, that evaluation did not identify manufacturing or other seam-related threats to the Pegasus
Pipeline. Exhibit 17, EMPCo TIARA Foreman to Conway Manufacturing Threat Classification
(July 26, 2006); Exhibit 18, EMPCo TIARA Foreman to Conway Risk Assessment Summary
(July 27, 2006).
Subsequent Seam Failure Susceptibility Analyses and Reassessment
In 2007, EMPCo performed another LSFSA of the Pegasus Pipeline. Exhibit 21, EMPCo
Foreman to Conway LSFSA and Pipelife Analysis Excerpts (2007). Once again, the evaluation
concluded that the line was not susceptible to long seam failure.11 Id. The Pipelife fatigue
analysis created (and applied in this instance) by Kiefner indicated that the Conway to Foreman
segment of the line had a remaining fatigue life of over 373 years and a 180 year reassessment
interval.12 Id.; Exhibit 1, Kiefner Affidavit ¶ 14 (stating that the Pegasus Pipeline “appeared to
have a theoretical fatigue life in excess of the conservative reassessment interval implemented by
EMPCo”). In 2009, after two years of operation and a planned expansion of the pipeline
throughput, the Company again reviewed its 2007 long seam failure analysis as well as the
metallurgical failure analyses, in preparation for a scheduled 2010 IMP reassessment of the line.
Exhibit 21, EMPCo Patoka to Corsicana LSFSA Review (2009); see also see Figure 3 EMPCo
IMP Assessment and LSFSA: Conway to Foreman.
The Company did run an ILI tool in 2010, although not a seam or crack tool. Exhibit 50, Final
ILI Report Conway to Corsicana (2010); see also Figure 3, EMPCo Conway to Foreman IMP
Inspection History. While the analysis of seam susceptibility did not change, the Company also
decided to schedule an ILI TFI seam/crack tool run on the Patoka to Conway section of the line.
Exhibit 29, EMPCO Conway to Corsicana LSFSA and Pipelife Excerpts (2011); Exhibit 35,
EMPCo Conway to Corsicana IMP IAD Form 3.2 (Mar. 15, 2011). That decision was made to
further evaluate the very risk factors that PHMSA now alleges were ‘not considered’ by the
Company. Subsequent long seam failure susceptibility analyses performed in 2011 indicated
that the Conway to Corsicana segment of the line still had over 20 years of remaining theoretical
fatigue life.13 Exhibit 29, EMPCO Conway to Corsicana LSFSA and Pipelife Excerpts (2011);
Exhibit 1, Kiefner Affidavit ¶ 14. Even though it was not required under the regulations, EMPCo
assessed the Corsicana to Conway section of the line with a TFI seam/crack tool in 2012 and
2013. Exhibit 54, EMPCo Conway to Corsicana GE PII TFI Final ILI Report (2013). As
                                                            
11

Exhibit 1, Kiefner Affidavit, ¶¶ 13;19 (noting that “it is reasonable to certify that hydrostatic test failures are not
an indication that the pipeline is susceptible to seam failures in the context of Part 195 IMP regulations” where there
is no evidence of fatigue related crack growth, selective seam corrosion or other time dependent defects, and
explaining that EMPCo’s conclusion in this instance was reasonable).

12

Specifically the Foreman to Conway section of the Pegasus Pipeline had a theoretical fatigue life of 373 years and
a reassessment interval of 186.6 years (with a safety factor of 2) with extremely light pressure cycling. Exhibit 21,
EMPCO Conway to Corsicana LSFSA and Pipelife Excerpt (2007).

13

This analysis indicated that the Conway to Corsicana segment had 21.8 years of theoretical fatigue life and a
reassessment interval of 10.4 years with light pressure cycling. Exhibit 29, EMPCO Conway to Corsicana LSFSA
and Pipelife Excerpts (2011).

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discussed in the preceding sections of this brief at the ultimate point of rupture was discovered
reported by the ILI vendor.
EMPCo Exceeded the Minimum IMP Requirements
As made evident by the above actions (documented in the record and attached Exhibits), EMPCo
clearly did consider the threat of long seam failure on LF-ERW pipe in the Pegasus Pipeline
system. Exhibit 2, Muhlbauer Affidavit ¶¶ 8, 11-12. Industry expert John Kiefner stated that the
Company’s conclusion that the failure segment was not susceptible under the federal regulations
was reasonable and consistent with available guidance prior to March 29, 2013 and that seamintegrity assessment activities employed on the segment were consistent with the IMP
regulations and guidance. Exhibit 1, Kiefner Affidavit ¶¶ 19, 21. In undertaking those
evaluations, the Company did more than the minimum required by IMP rules, not less. Exhibit
2, Muhlbauer Affidavit ¶¶ 6-7 (noting that EMPCo’s IMP manual “is among the most complete
and well-written of the many such manuals I have seen”). Moreover, the Company’s IMP plan,
procedures and outputs were developed and applied in close consultation with industry experts
often used and relied upon by PHMSA, even in the NOPV documentation presented in this
proceeding. See e.g., Exhibit 1, Kiefner Affidavit ¶10.
PHMSA regulations require pipeline operators to consider risk factors such as susceptibility to
seam failure, but they do not require that an operator conclude such a risk exists simply because
LF-ERW pipe is present. In this instance, EMPCo clearly did consider seam failure as a risk,
and it repeated that evaluation process multiple times, eventually running a seam/crack ILI tool
that the Agency alleges should have been run if the Company had concluded that a risk of seam
failure was present. The seam/crack ILI tool did not identify any actionable anomaly.
The allegations in Item 1 of the NOPV are incorrect, and the alleged violation should be
withdrawn.
NOPV Item 2: Alleged Failure to Establish Five Year Reassessment Interval
In Item 2, PHMSA alleges that EMPCo failed to establish a five year reassessment interval
pursuant to 49 C.F.R. Part 195.452(j)(3). That allegation hinges on the Agency’s assertion in
NOPV Item 1 that the Company should have determined that the Pegasus Pipeline was
susceptible to seam failure. The NOPV asserts that the Company should have concluded, on the
basis of the 2005 and 2006 BAP hydrotests, that the line was in fact susceptible to seam failure
and should have established a five year reassessment interval. As discussed above in response to
Item 1, the Company did carefully consider the 2005–2006 hydrotest data with regard to the risk
of seam failure. The Company also consulted with both Kiefner and Muhlbauer on these issues.
Exhibit 1, Kiefner Affidavit ¶¶ 11-12; Exhibit 2, Muhlbauer Affidavit ¶ 6. The conclusion from
that review was that there was no evidence of either pressure cycling induced fatigue or
preferential seam corrosion. Exhibit 14, EMPCo Corsicana to Patoka Summary of Hydrotest
Learnings (July 6, 2007); Exhibit 21, EMPCo Foreman to Conway LSFSA and Pipelife Analysis
Excerpts (2007); see also Exhibit 1, Kiefner Affidavit ¶¶ 19, 21.
Because the Company’s analysis of seam failure susceptibility concluded that the Pegasus
Pipeline was not susceptible under the federal regulations, there was no requirement under IMP
to schedule a seam tool. Thus, the Company did not violate the requirement to establish a five
year reassessment interval for a seam or crack ILI tool.
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The Agency’s allegations in Item 2 of the NOPV can only have relevance if the allegations in
Item 1 are deemed correct. Since the Company clearly did consider the risk of seam failure
susceptibility (Item 1) and concluded that the risk was not significant, then there was no
requirement to establish a five year interval to reassess the risk not found (Item 2). PHMSA’s
allegations therefore fail in both Item 1 and Item 2. Because the pipeline was not determined to
be susceptible to seam failure in accordance with applicable law and guidance, no seam/crack
tool inspection was required to be performed on five year intervals.
Ironically (in light of the allegations of the NOPV), the Company did run a seam ILI tool to
further evaluate the potential risk of seam failure, even though it was not required to do so. And
the Company continued to review its reassessment and tool type schedules based on pressure
cycle fatigue calculations using the Pipelife software developed for EMPCo by Kiefner. Exhibit
1, Kiefner Affidavit ¶¶ 19, 21 (noting that EMPCo’s activities were consistent with the
regulations and the Baker Report flow chart). As explained in the Baker/Kiefner Report:
If no fatigue-related failures exist, it is reasonable to certify that the pipeline is not
susceptible to seam failures in the context of federal integrity management requirements.
This does not, however, necessarily preclude the need for periodic reassessment. A
reassessment interval should be calculated using the best available information. As more
information is gained and new tools developed, the need for and timing of future
reassessments can be re-evaluated.
Baker/Kiefner Report, p. 26; see also Exhibit 1, Kiefner Affidavit ¶ 13 (noting that if there is no
evidence of fatigue related crack growth, selective seam corrosion or evidence of other time
dependent defects such as stress corrosion cracking, “it reasonable to certify that the hydrostatic
test failures are not an indication that the pipeline is susceptible to seam failures in the context of
the Part 195 IMP regulations”). In doing all of this, the Company was expressly going beyond
the regulatory requirements, in keeping with the Agency’s directive that an operator’s integrity
management program should be a dynamic and iterative process.
The allegations in Item 2 of the NOPV are incorrect, and the alleged violation should be
withdrawn.
NOPV ITEM 3: Alleged Failure to Follow IMP Plan Procedure
In Item 3 of the NOPV, the Agency alleges that EMPCo failed to follow its own IMP procedure
found at Section 5.1 of its IMP Manual. That procedure implements the requirements of Part
195.452(j)(3), to provide for “continual evaluation and assessment” of pipeline segments subject
to IMP. The NOPV specifically alleges that the Company improperly changed the timing of a
planned ILI for the pipeline, extending it from “prior to [the end of] 2011” to late 2012 or early
2013, without providing advance notice to PHMSA.
As discussed in response to Items 1 and 2 above, the Company properly followed the IMP
regulations by considering whether the pipe at issue was susceptible to long seam failure, in
compliance with 49 C.F.R. Part 195.452(e)(1). This consideration was fully documented, and
included input and review by John Kiefner, whom the Agency recognizes as a national expert
and who created the PHMSA-endorsed process for evaluation of LF-ERW longitudinal seams
under IMP.
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Following its IMP procedure, the Company concluded that the pipe segment was not susceptible
to seam failure in 2007, 2009 and again in 2011. PHMSA reviewed EMPCo’s IMP procedures
and LSFSA analysis on multiple occasions (2003, 2007 and 2011), including an in-depth review
of the Pegasus system specifically in 2007, and did not raise any concerns.14 As a result of the
Company’s determination that the line was not susceptible to seam failure, no seam reassessment
was required. Based on the 2010 ILI on the segment at issue and subsequent risk analysis, the
next required integrity reassessment date was July of 2015. The Company nevertheless elected
to run a seam tool ILI well in advance of that date, which was not required by the rules because
the pipe was not deemed susceptible to seam failure. As this tool run was not required, it was
not subject to the variance reporting requirements at 49 C.F.R. Part 195.452(j)(5) or EMPCo’s
IMP manual. See Exhibit 4, EMPCo IMP Manual Excerpts Section 5.1(4) Continual Evaluation. The
seam/crack tool ILI was voluntarily run in advance of the incident, but no actionable anomaly at
the point of rupture was reported by the ILI vendor.
The fact that the Company elected to use the seam/crack ILI tool even though it was not required
illustrates EMPCo’s diligent and proactive approach, and willingness to go beyond minimal
requirements. The ILI tool that the Agency insists should have been run was, in fact, run well in
advance of the required reassessment interval, and before the incident occurred. Because it was
a discretionary tool run, there was no requirement to provide written notice to the Agency or
complete a Management of Change (MOC) document and the Company was free to modify its
internal schedule for such a discretionary action. The Company did meet the reassessment
intervals for ILI referenced by PHMSA and it did voluntarily run a seam tool even though not
required. Most significantly, that tool run did not report any actionable anomaly, which further
supports the fact that the Agency’s complaint in this Item is both unfounded and irrelevant.
The allegations in Item 3 of the NOPV are incorrect, and the alleged violation should be
withdrawn.
NOPV Item 4: Alleged Failure to Prioritize Pipeline Segments for Reassessment in
Integrity Assessment Schedule that Posted Highest Risk to HCAs
The Agency alleges in Item 4 of the NOPV that the Company failed to prioritize the Pegasus
Pipeline segments that posed the highest risk to high consequence areas (HCAs) before
reassessing lower risk segments. Citing 49 C.F.R. Parts 195.452(e) and (j)(3) again, the Agency
alleges that EMPCo failed to prioritize the Corsicana to Conway segment higher than the Patoka
to Conway segment for reassessment related to manufacturing flaws and seam failure
susceptibility. The record clearly shows, however, that the Company did carefully consider all
identified risk factors in planning the reassessment intervals for the Pegasus Pipeline and that
those considerations were well documented.
The Company properly followed the IMP regulations by considering all risk factors reflecting
the risk conditions on the segments as required under 49 C.F.R. Parts 195.452(e) and
195.452(j)(3). See Exhibit 2, Muhlbauer Affidavit ¶¶ 11-12 (stating that EMPCo “properly
recognized the issues associated with LF-ERW pipe, reacted to the threats on the Pegasus
pipeline, and complied with the Part 195 IMP regulations”). EMPCo’s risk assessment process
was drafted with input and review from Kent Muhlbauer, a nationally recognized expert on
                                                            
14

As discussed supra at p. 11.

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pipeline risk management. Exhibit 2, Muhlbauer Affidavit ¶¶ 6-7. As discussed above, the IMP
rules do not mandate how operators assign risk scores to each risk factor or how they prioritize
assessments, but require that operators consider the regulatory factors and conduct a meaningful
analyses of their particular systems.
As described above, following its IMP procedures, the Company’s risk assessments and
evaluation did not identify long seam failure susceptibility or manufacturing as risks to either the
Patoka to Conway or Conway to Corsicana segments. Exhibit 19, EMPCO Risk Assessment
Summaries for Patoka to Corsicana (2006). Further, the 2007 risk scores on both segments were
practically identical.15 Even though it was not required under Part 195 or EMPCo procedures,
when planning the reassessment tools in 2009, the Company made the decision to assess the
Patoka to Conway segment with a TFI seam/crack tool. This decision was based on the fact that,
as compared to the Conway to Corsicana segment, the Patoka to Conway segment experienced
more hydrostatic seam failures on a LF ERW per mile basis, more pressure reversals, and shorter
fatigue lives based on 2007 data.16 Exhibit 22, EMPCO Patoka to Corsicana LSFSA Review
(2009). In addition, the Patoka to Conway segment experienced three girth weld leaks that were
not present on the Conway to Corsicana segment.
As with Items 1-3 of the NOPV, Item 4 is based on an inaccurate and improper assumption and
should be withdrawn. The Company considered seam susceptibility many times, and concluded
that no significant risk was present. Given such well-documented and careful consideration of
all known risk factors, there was no legal requirement to run a seam/crack tool, there was no
obligation to schedule a five year reassessment interval of a tool not required, and there was no
requirement to prioritize one segment differently than another. A seam tool was voluntarily run,
resulting in no reported anomalies at the point of failure.
NOPV Item 5: Alleged Failure to Take Prompt Action to Address All Anomalous
Conditions by Not Declaring Discovery of Immediate Repair Conditions
PHMSA alleges that EMPCo failed to declare discovery of immediate repair conditions from
information received in preliminary reports from the ILI vendor, and, as a result, treated
“Immediate Conditions” as “Validation Digs” or “Confirmation Digs.” The Agency argues that
this failure led to a violation of 49 C.F.R. Part 195.452(h) because EMPCo failed to take
appropriate action for “Immediate Conditions.” PHMSA claims that EMPCo received a
preliminary report on August 9, 2010, identifying two “Immediate Conditions” at MP 164.051
and MP 142.394. The Agency further alleges that MP 164.051 was not addressed until August
28, 2010, and that MP 142.394 was not addressed until several months after the report on
January 6, 2011. PHMSA’s allegations are unfounded, and based on incorrect factual
assumptions and conclusions.
                                                            
15

The TIARA risk scores on the Patoka to Conway and Conway to Corsicana segments in 2006 were roughly the
same, both in the D3 range on the EMPCo IMP Risk Matrix. Pursuant to the EMPCo Risk Matrix Methodology, a
score of D3 estimates that the probability of an event is very unlikely and that the consequences of an event may
include restricted work or medical treatment and/or potential short term or minor adverse environmental impacts,
among other consequences. Exhibit 6, Attachment #1 to EMPCO OIMS System 2A. For this risk category, there are
no further (P&M) actions to consider. Id.
16

The EMPCo 2011 fatigue analyses cited in the NOPV were not performed until after the 2010 assessments were
completed.

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In the first instance, the anomaly at MP 164.051 was identified as a 72% external metal loss call
in a preliminary report dated and received by the Company on August 23, 2010. Exhibit 23,
EMPCo Email from NDT (8/23/10); Exhibit 24, EMPCo NDT Preliminary ILI Report (Aug. 23,
2010). PHMSA’s erroneous allegation that the report was received on August 9, 2010, is based
on the date of an underlying dig sheet maintained by the vendor, not the date the preliminary
report was received by EMPCo. Ironically, PHMSA correctly notes the receipt of the
preliminary report in the Table included in NOPV Item 6 (last line, second column). The
Company factored in tool tolerance and declared discovery of this anomaly as a potential
immediate repair on the same day it received the preliminary report, August 23, 2010. The
anomaly was repaired just five days later, on August 28, 2010. Exhibit 25, EMPCo Repair Form
PL-0751 (Aug. 28, 2010).
EMPCo became aware of the second anomaly, MP 142.394, in the final report received by the
Company from the vendor on January 10, 2011.17 Exhibit 30, Email from NDT and MP 142.39
Dig Sheet (Jan. 10, 2011). This anomaly was not identified in any preliminary report. The
anomaly was found to be a 0.74% top dent with an external corrosion pit, believed to be
associated with original construction. The Company acted within two days of receiving the final
report, repairing the anomaly on January 12, 2011. Exhibit 31, EMPCo Repair Form PL-0751
(Jan. 12, 2011).
The factual basis for the allegations in NOPV Item 5 are simply inaccurate and the suggestion of
any violation is without foundation and should be withdrawn. As set forth above and reflected in
the record, EMPCo complied with the discovery deadline for “Immediate Conditions” set forth
by the applicable regulations in both instances cited by PHMSA.
NOPV Item 6: Alleged Failure to Declare Discovery of Condition within 180 Days
In Item 6 of the NOPV, PHMSA alleges that EMPCo failed to declare discovery within 180 days
on four separate occasions on the Patoka to Corsicana segments of the Pegasus Pipeline in 2010,
2011 and 2013. PHMSA specifically asserts that EMPCo had sufficient information from the
ILI vendor to make such determinations, again citing to 49 C.F.R. Part 195.452(h). To the
contrary, the record confirms that in all instances the tool vendor did not provide EMPCo with
the ILI data until nearly the conclusion of the 180-day period, making it impracticable to declare
discovery within the 180 day timeframe. Exhibit 26, EMPCo IMP Form 1.2 (Dec. 17, 2010);
Exhibit 33, EMPCo IMP Form 1.2 (Jan. 31, 2011); Exhibit 38, EMPCo IMP Form 1.2 (Aug. 2,
2013); Exhibit 39, EMPCo IMP Form 1.2 (Aug. 28, 2013). Consistent with IMP regulations, the
Company’s IMP Manual provides that discovery is required within 180 days of running the ILI
tool, unless there are circumstances that make discovery impractical. Exhibit 4, EMPCo IMP
Manual Excerpts Section 4.4 Timeliness of Discovery; 49 C.F.R. Part 195.452(h)(2). Until the
Company can verify the ILI vendor data and complete data integration, the Company does not
have sufficient information to declare discovery. The Company followed its procedure, as
established in its IMP Manual, to extend the 180-day timeframe with adequate justification. See
Figure 4, Summary of Discovery Dates for ILIs Referenced in PHMSA NOPV.
                                                            
17

The PHMSA PSVR includes as support a PL-0751 repair form associated with a different immediate anomaly
located at MP 274.091 and odometer number 296278.97. This anomaly was discovered when EMPCo received the
final ILI report on January 10, 2011 and was repaired on January 13, 2011 (when the inspector signed the repair
form). Exhibit 32, EMPCo Repair Form PL-0751 MP 274.09 (Jan. 13, 2011).

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 Figure 4: Summary of Discovery Dates for ILIs Referenced in PHMSA NOPV

 

ILI Tool Date of Date(s) of IIVIP Form 180 Day Date of Revised
(date Final 1.2 Extension Request Deadline Discovery Deadline**
completed)* Report

 

 

 

 

 

 

Patoka to Conway

 

MFL- 12/30/10 1/31/11 2/11/11 3/4/11 3/11/11
Combo and
TFI
(8/15/10)

 

 

 

 

 

 

 

Conway to Corsicana

 

 

 

 

 

 

MFL 1/7/11 12/17/10 1/17/11 3/15/11 3/17/11
Combo

(7/21/10)

TFI 8/29/13 8/2/13: 8/28/13 8/5/13 10/7/13 10/7/13
(2/6/13)

 

 

 

 

 

 

*This is the date the last tool entered the receiving trap.
**Exception approved due to delayed receipt of fmal ILI vendor report.

The Agency?s allegations in this instance are unformded, given that the Company followed its
procedures and the IMP regulations. Moreover, it is peculiar that PHMSA would allege this
violation given that the Agency has not even responded to on proposed revisions to its
IMP Manual on this very issue of whether an operator has suf?cient information to declare
discovery.18

NOPV Item 7: Alleged Failure to Follow Procedure for Updating Risk Assessments as
Changes Occur

PHMSA alleges in Item 7 that did not follow internal procedures IMP 5.4 and OIMS 2.4
regarding updating risk assessments in response to potential threat changes, citing again to 49
.F.R. Parts and The Agency argues that should have updated its risk
assessment when the Company extended the inspection timing of the TFI seam/crack tool on the
Conway to orsicana segment and that this omission resulted in the failure to identify threats and
preventive and mitigative measures. In contrast, the record shows that no updated risk
assessment was required under IMP 5.4 or 2.4.

 

18 In 2013. PHMSA cited for a similar violation in a prior NOPV for which a Petition for Reconsideration is
pending. PHMSA Final Order, CPF No. 4?2011?5016 (June 2 7, 2013). As part of that action. PI-IMSA issued a
Compliance Order with two items. Item 1 of the Compliance Order has been stayed pending a decision on the
Petition. and timely submitted revised procedures under Item 2 of the Compliance Order to the Southwest
Region on August 1. 2013. PHMSA Inspector John Pepper responded to the proposed revisions requesting
additional modi?cations on August 5. 2013: EMPCO addressed those in a further revised version submitted to
PHMSA on August 29. 2013.

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EMPCo OIMS Element 2.4 states that “risk assessments are updated at specified intervals and as
changes occur” and EMPCo IMP Section 5.4 requires annual review of integrity conditions and
when significant changes occur, an updated risk assessment. Exhibit 5, EMPCo OIMS
Framework Element 2.4; Exhibit 4, EMPCo IMP Manual Excerpt Section 5.4. As discussed above,
the March 2011 long seam failure susceptibility analysis determined that the Conway to
Corsicana segment was not susceptible to seam failure and identified a conservative interval for
seam reassessment by the summer of 2013. Exhibit 29, EMPCo Conway to Corsicana LSFSA
and Pipelife Analysis Excerpts (2011); Exhibit 35, EMPCo IMP IAD Form 1.2 Conway to
Corsicana (3/15/2011). Because this analysis did not change after March 2011 and no other
integrity conditions changed, there was no requirement to revise the risk analysis. Further, a
revised analysis would not have impacted the threat identification or any of the preventive or
mitigative measures for this segment because the risk analysis did not rely upon the
implementation of a seam/crack tool inspection in 2011 or 2012.
The allegations of Item 7 of the NOPV are without foundation because the requirement in
EMPCo’s procedures to perform an updated risk assessment did not apply in this instance. The
fact that the Company recommended, scheduled, and employed a TFI seam/crack tool in advance
of the conservative Pipelife reassessment interval demonstrates that EMPCo’s IMP exceeded
Part 195 integrity management rules. Moreover, it is illogical to assume that the anomaly at the
ultimate point of rupture would have been reported by an earlier TFI seam/crack tool run. No
anomaly was reported when EMPCo ran the tool in 2012-2013. Given that crack growth is
associated with the passage of time, the anomaly at the point of rupture was even less likely to be
detected at the earlier date when PHMSA alleges the tool should have been run.
NOPV Item 8: Alleged Failure to Follow O&M Procedure by Selective Use of Threat
Identification and Risk Assessment Manual Process Results
In Item 8 of the NOPV, the Agency alleges that EMPCo failed to follow its Operations and
Maintenance (O&M) procedures required under 49 C.F.R. Part 195.402 by selectively using its
TIARA process in 2011, and that this led to a failure to properly characterize the result of a
release to certain HCAs on the Conway to Foreman segment, including the Lake Maumelle
Watershed. In actuality, the Agency appears to be asserting a violation of the IMP threat
identification and analysis requirements set forth in 49 C.F.R. Part 195.452. The record clearly
shows, however, that the Company’s IMP, Operations Integrity Management System (OIMS),
and TIARA procedures were consistent with applicable law. Further, EMPCo properly applied
those processes which led to the identification of certain preventive and mitigative (P&M)
measures to protect HCAs, including scheduling the installation of three emergency flow
restriction devices (EFRDS) (two in the Lake Maumelle area) and running a TFI seam/crack
tool. Exhibit 36, EMPCo Conway to Corsicana P&M Form 6.1 (7/21/11); Exhibit 37, EMPCO
Conway to Corsicana EFRD Form 6.2 (7/21/11).

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As discussed above, when performing its risk assessment analysis and continual evaluation, the
Company properly followed the relevant Part 195 regulations and its own procedures which were
drafted with input from key industry experts. Exhibit 2, Muhlbauer Affidavit ¶¶11-12 (stating
that EMPCo “properly recognized the issues associated with LF-ERW pipe, reacted to the threats
on the Pegasus pipeline, and complied with the Part 195 IMP regulations”). EMPCo identified
HCA locations and types, including Lake Maumelle and other water bodies, and included them
in the TIARA risk assessment dynamic segmentation and calculations. Exhibit 7, EMPCo
TIARA Manual Excerpts; Exhibit 28 EMPCO TIARA UDT Q&A Conway to Corsicana (2011)
(assessing a score of 57 for sensitive receptors above a 55 for high level of public concern). In
addition, these sensitive areas and drinking water bodies were expressly considered in the
Company’s IMP P&M measures analysis. Exhibit 36, EMPCo Conway to Corsicana P&M Form
6.1 (7/21/11) (considering whether drinking water bodies are potentially affected HCAs); Exhibit
37, EMPCO Conway to Corsicana EFRD Form 6.2 (7/21/11)(considering the same).
In 2011, the TIARA process did not result in any identified threats and did not in turn trigger any
requirement to re-characterize the risk of release to HCAs on the Conway to Corsicana segment.
Exhibit 34, EMPCo Conway to Corsicana Manufacturing Risk Assessment (2011); Exhibit 36
Conway to Corsicana P&M Form 6.1 (7/21/11). Despite this fact, and the fact that a valve
would not significantly reduce the modeled risk or consequence as defined by the regulatory
criteria and TIARA modeling, EMPCo’s IMP Data Integration Team recommended further
review of proposed EFRD sites in the Lake Maumelle watershed area and the Cedar Creek
Reservoir as risk reduction measures. Exhibit 37, EMPCO Conway to Corsicana EFRD Form
6.2 (7/21/11). This led to the decision to install three EFRDs in this area. As noted by risk
management expert, Kent Muhlbauer, “risk reduction measures were chosen in proportion to
perceived risks and in light of other potential incident scenarios, consistent with requirements
and objectives of regulatory IMP.” Exhibit 2, Muhlbauer Affidavit ¶ 12.
The allegations of Item 8 of the NOPV are without foundation because the Company complied
with its own procedures and with applicable law. The fact that the Company identified the
potential need for EFRDs in HCAs along the Conway to Corsicana segment shows EMPCo’s
diligence in going beyond minimal Part 195 requirements.  
NOPV Item 9: Alleged Failure to Follow Procedure for Continual Evaluation and
Assessment
In Item 9 of the NOPV, the Agency alleges that EMPCo failed to follow its Management of
Change (MOC) procedure OIMS 7.2 when it merged testable segments in 2009. PHMSA
contends that the longer testable segments negatively impacted the TIARA risk assessments by
diluting risk scores on the Conway to Foreman segment. The record will show, however, that
EMPCo complied with this its MOC procedure and that merging the segments could not have
negatively impacted the risk assessment.
EMPCo’s OIMS Management of Change process ensures that operational, procedural and
physical changes are implemented in a systematic manner intended to ensure the integrity of
EMPCo facilities. Exhibit 5, EMPCo OIMS Framework Element 7.2. As discussed above, the
Company completed MOC forms in 2005 that expressly considered the impact of the merger of
testable segments on IMP risk assessments and concluded that there was no negative impact to
the integrity risk assessment process. Exhibit 10, EMPCo Management of Change Form No. 0522
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2829 (8/10/05); Exhibit 11, EMPCo Management of Change Form No. 05-2833 (8/10/05).
Under the EMPCo TIARA dynamic risk segmentation, threats cannot be aggregated or masked
over multiple miles. For that reason, the length of a testable segment does not impact the risk to
any specific area of the pipeline. In short, the Company combined the testable segments in
compliance with applicable law and this decision did not mask risk on the intermediate
segments.
V.

THE PROPOSED PENALTY IS NOT WARRANTED
A.

Strict Liability is not Provided in the PSA, thus there is No Basis for the
Alleged Violations or Proposed Administrative Penalties

As discussed in the preceding sections of this brief, the NOPV presumes that simply because an
incident occurred, there have been violations of PHMSA’s Part 195 regulations. That
presumption would only apply if the PSA had a strict liability provision, but it does not.
Although infrequent, it is possible for an incident to occur even when a pipeline operator has
fully complied with applicable law. This is one such instance.
In the absence of regulatory violations, there is no basis for administrative penalties. EMPCo
was in compliance with PHMSA’s Part 195 regulations in regard to the Pegasus Pipeline. Thus,
the alleged violations asserted in the NOPV are based on mistakes of fact and law and should be
withdrawn entirely. In that event, no penalty is appropriate.
B.

Even if it is Found that Violations did Occur, the Amount of the Penalty
Proposed is Unwarranted 

The Agency’s proposed penalty of more than $2.6 million is not authorized by law. The penalty
provisions of the PSA establish three limitations on the amount of civil penalties proposed in any
PHMSA enforcement proceeding. First, Section 2 of the PSA establishes factors that the
government must (“shall”) consider in developing an appropriate proposed civil penalty for a
pipeline incident. 49 U.S.C. § 60122(b) (those factors appear again in PHMSA regulations at 49
C.F.R. Part 190.225). Second, any violation occurring prior to January 3, 2012, must be limited
to a maximum penalty of $100,000 per day. 49 U.S.C. § 60122(a)(1). Third, any “related series
of violations” occurring prior to January 3, 2012, must be capped at no more than $1 million. 49
U.S.C. §60122(a)(1); 49 C.F.R. Part 190.223(a). 19 Each of the nine Items in the NOPV is
alleged to have commenced prior to January 3, 2012. Moreover, many of the allegations rely on
the same purported evidence, thus the statutory cap of $1 million should apply.

                                                            
19

In reviewing the issue of civil penalty caps in the Pipeline Safety Act (PSA) during reauthorization efforts
preceding the enactment of the Pipeline Safety Improvement Act of 2002, Senators Hollings and Kerry had the
following exchange on the phrase “related series of violations”: [Sen. Hollings]: “I am seeking clarification that all
information requests issued by the Secretary pursuant to a single incident investigation are considered “related” for
purposes of calculating the $1,000,000 civil penalty cap for a ‘related series of violations’…” [Sen. Kerry]: “It is
the intention of this legislation to treat all information requests pursuant to a single incident investigation as
‘related’ for purposes of applying the civil penalty cap…” Senator Hollings (SC) and Senator Kerry (MA).
“Pipeline Safety Improvement Act.” Congressional Record 146:103 (Sept. 7, 2000), p. S8235.

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1.

PHMSA’s Statutory Penalty Authority 

Until recently, PHMSA had not assessed administrative civil penalties in excess of the daily or
“related series of violations” maximums, thus the manner in which PHMSA seeks to use its
penalty authority is an issue of critical importance for both the Agency and the industry. The
statutory language authorizing PHMSA penalty authority has not changed since it was enacted
more than thirty years ago (other than to increase the maximum amounts available), and there is
very little legislative history providing guidance on how the Agency should exercise its penalty
authority. Similarly, the Agency has not issued any regulation or policy describing how it will
apply its penalty authority, or how it intends to interpret the phrase “a related series of
violations.”
The only relevant guidance that the Agency has issued to date is its decision In re: Colorado
Interstate Gas Co., CPF 5-2008-1005 (Nov. 23, 2009) (CIG). In CIG, the Agency stated that it
interpreted the phrase “related series of violations” to mean “a series of daily violations” of the
same regulatory requirement. Id. at p. 11. To do otherwise, the CIG decision reasoned, “would
effectively limit the number of violations that PHMSA could assess penalties on” in a given
incident. Id. We disagree. Congress could have stated (and has, in other statutes20) that the
penalty cap applied only to “multiple violations of a single requirement,” but it did not use that
language. Instead, it established a cap on “related series of violations.” As noted in the
Congressional Record, Senators Kerry and Hollings interpreted this phrase to mean “all
violations related to a single incident,”21 and that is the interpretation that it should be given in
this proceeding. The statutory language is further supplemented by the CIG decision where the
Agency held that Items in a NOPV may also be “related” (even if not daily violations of the
same requirement) if the facts and law for the claims are “so closely related … that they are not
separate and should be considered one violation.” CIG, at 12.
2.

The NOPV As Drafted Alleges a “Related Series of Violations”

Following the reasoning of the CIG decision (and the clear language of the statute), Items 1, 2, 3
and 4 of the NOPV in this case are clearly related. All four of those Items are inextricably
intertwined, relying on the same facts and law. The essence of the Agency’s claims for Items 1
through 4 of the NOPV is that EMPCo failed to properly conclude that the pipe segment at the
point of rupture was susceptible to seam failure. As stated above in this brief, the Company
believes that the IMP rules do not dictate a particular conclusion, but only a deliberative process.
The Company undertook that process and documented it. Unfortunately, an incident occurred,
despite the fact that the Company followed applicable law, and despite the fact that state of the
art technology did not detect an actionable anomaly at the point of rupture prior to the incident.
But for the Agency’s allegation that the Company failed to conclude that the pipe segment was
susceptible to seam failure, there would be no basis for the purported violations asserted in Items
1 through 4. Item 1 specifically addresses the alleged failure to conclude that the pipe was
susceptible to seam failure. Item 2 builds on that same allegation, by asserting that because the
                                                            
20

See e.g., Social Security Act, 42 U.S.C. §1320(d)5(a)(3) (setting a maximum cap multiple violations of a single
requirement).

21

See f n. 19.

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Company did not conclude that the segment was susceptible to seam failure, it exceeded the
length of time allowed to run a seam ILI tool (note that the Company ran other ILI tools during
the five years in issue; it did run a seam tool only a few months after the five years in issue, even
though not required by law; and the ILI seam tool was run before the incident occurred, reporting
no actionable anomaly at the point of rupture). The Agency’s PSVR cites the same evidence in
support of both Items 1 and 2 (hydrostatic test data and IMP assessment worksheets). PSVR, pp.
7, 13.
Items 3 and 4 of the NOPV continue this reliance on a single allegation, using similar evidentiary
support and referencing either directly or indirectly the same Part 195 regulations. Item 3 asserts
that the Company failed to complete a Management of Change form for extending the five year
reassessment interval invoked in Item 2. Again, but for the presumption that the rules require an
operator to conclude, not just consider, that LF-ERW pipe is susceptible to seam failure, then
there is no basis for a violation in Item 3 (or 1, or 2). The same holds true in regard to Item 4,
which alleges – again – that because EMPCo failed to conclude the pipe was susceptible to seam
failure, it did not properly prioritize the timing of the ILI seam tool runs on segments of the
Pegasus pipeline.
There is only one alleged fact central to Items 1 through 4 of the NOPV, being that the Company
failed to conclude seam failure susceptibility. Without that assertion, there is no basis for any
violation of law in any of these four Items. For that reason, using both the plain language of the
statute and the rationale articulated by the Agency in the CIG decision, Items 1 through 4 of the
NOPV constitute “a related series of violations” that are “so closely related … that they are not
separate and should be considered one violation.” CIG, at 12.
Items 1 through 4 of the NOPV should be combined for proposed penalty purposes, with the
combined penalty not to exceed $1 million.
3.

The Proposed Penalty Fails to Consider and Appropriately Apply All
Mitigating Factors 

Even if the Agency (or the courts) concludes that Items in the NOPV are not a “related series of
violations” in whole or in part, and thus not subject to the $1 million penalty cap, the combined
proposed penalty does not take into account all factors associated with the incident, as required
by the PSA and PHMSA regulations. 22 EMPCo requested and was provided a copy of
PHMSA’s PSVR for this matter, and although it does not specifically provide numeric penalty
calculations (see discussion in Section 4 below), the PSVR does provide the Agency’s mitigating
factor analysis (i.e., nature, circumstances, gravity, culpability, good faith, and other matters as
justice may require) for each alleged violation. EMPCo does not intend to address each
component of each violation, but it generally contests the mitigation analysis set forth in the
PSVR. For instance, the report repeatedly alleges that the Company made conscious decisions
not to comply with regulatory requirements that were clearly applicable,23 and that it did not
                                                            
22

49 C.F.R. Part 190.225 states that “in determining the amount of a civil penalty…the [Agency] shall consider,”
among other things, the nature, circumstances and gravity of the alleged violation, as well as any good faith by the
Respondent in attempting to achieve compliance. 49 C.F.R. Part 190.225 (emphasis added).
23

PHMSA’s own PSVR notes that EMPCo’s response to the incident was timely, appropriate and in accordance
with the Company’s procedures. PHMSA PSVR, CPF 4-2013-5027, pp. 11, 14.

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make reasonable interpretations of regulatory requirements. The record in this matter shows that
the Company clearly complied with applicable regulatory requirements regarding IMP, and that
it did not at any time make conscious decisions to disregard the law.
In addition, although the specific calculations of the proposed penalty have not been made
available, the proposed penalty does not appear to consider the fact that EMPCo fully cooperated
with all federal, State and local officials in good faith while responding to and investigating the
causes of the incident. To date, the Company has spent more than $75 million in response to the
Mayflower incident, and continues to review and revise its Integrity Management Program as a
result of the incident. If for no other reason, the penalty proposed in this NOPV should be
reduced in light of the cooperation and good faith shown by EMPCo in its efforts both during
and after the incident, both of which are mitigating factors set forth in 49 C.F.R. Part 190.225.
4.

Due Process Requires that an Agency’s Penalty Rationale Be
Articulated  

Finally, the proposed penalty for this matter should be reduced for due process and policy
reasons, because the NOPV as issued provided no explanation for the basis of the penalty, which
on its face exceeds the statutory cap. PHMSA practice has evolved in recent years in terms of
how the Agency interprets and applies its penalty authority. At present, the Agency does not
provide any explanation in a NOPV of how a penalty was derived, or whether multi-day
assessments are included.
Although many administrative agencies have published official penalty policies to explain how
they intend to interpret and apply their statutory penalty authority, PHMSA has promulgated no
such policy. Nor has it produced any guidance, interpretative letters or advisories for the
regulated community and the public to refer to in anticipating how the Agency should or will
exercise its penalty authority.
The Administrative Procedure Act (APA) requires that respondents be informed of “the matters
of fact and law asserted” in any enforcement pleading, which should include a clear statement of
the theory on which the agency will proceed with its case, such that the respondent understands
the issues and is afforded full opportunity to present its defense at a hearing. 5 U.S.C. 554(b);
Yellow Freight System v. Martin, 954 F.2d 353, 357 (6th Cir. 1992).
PHMSA’s failure to expressly allege multi-day or statutory maximum claims in its NOPV
violates the due process requirements of the Constitution and the procedural requirements of the
APA. As a matter of equity, policy and due process considerations, the Agency should reduce
the proposed penalty in this matter. Penalty adjustment in this instance would benefit both the
Agency and the regulated community by clarifying the application of the CIG decision.
VI.

THE PROPOSED COMPLIANCE ORDER IS OVERBROAD

The Proposed Compliance Order (PCO) requests actions by the Company to review and improve
management systems in regard to Items 1, 2, 5, 6 and 8 of the NOPV. There are nine separate

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substantive paragraphs in the PCO.24 Paragraph 1 of the PCO is notably more expansive than the
other elements of the PCO.
Paragraph 1 relates to Item 1 of the NOPV, and requests that the Company modify its IMP
procedures concerning seam failure susceptibility analyses, seam integrity assessment plans and
threat modeling. Item 1 of the PCO is intended to broadly address “all pre-70 ERW pipe on any
assets covered by the operator’s IMP.” NOPV, p. 10 (emphasis added). None of the other
requested actions in the PCO address “all assets” of the Company. Such an extension of
requested relief regarding modification of IMP procedures relating to pre-70 ERW pipe outside
of the Pegasus system goes beyond the specific facts and issues presented in the NOPV, and
exceeds the scope of relief necessary to remedy the alleged harm in this case.
Established law holds that injunctive relief must be narrowly tailored to remedy the specific
harm alleged, and that an overbroad scope of injunctive relief is an abuse of discretion. Ahearn
ex rel. N.L.R.B. v. Remington Lodging & Hospitality, 842 F. Supp. 2d 1186, 1205-1206 (D.
Alaska 2012), appeal dismissed (Apr. 6, 2012), citing Park Vill. Apartment Tenants Ass’n v.
Mortimer Howard Trust, 636 F.3d 1150, 1160 (9th Cir. 2011). An administrative agency may
not impose sanctions that are unwarranted in law or without justification in fact. Am. Power &
Light Co. v. Sec. & Exch. Comm'n, 329 U.S. 90, 112-13 (1946); Syverson v. U.S. Dep't of Agric.,
601 F.3d 793, 800 (8th Cir. 2010). Accordingly, the PCO requirements constitute an abuse of
agency discretion and are potentially subject to judicial review under the APA.
As made evident in this brief, EMPCo recognizes that the IMP rules intend that both industry
and the Agency learn from incidents as part of the process of continual evaluation, regardless of
whether violations of the rules occurred. The Company has already begun a review of its IMP
program and procedures in light of the Pegasus incident, and it intends to continue that review
and revision even before a Final Order issues in this case (at which time any proposed
Compliance Order would take effect). The ongoing review that is being undertaken by the
Company is expected to fully address the terms of the PCO (including Paragraph 1), but the
Company respectfully reserves its objections as stated.
VII.

SUMMARY AND RELIEF REQUESTED

It is clear that PHMSA issued this NOPV solely because a high profile incident occurred.
EMPCo does not minimize the significance of the incident; the Company has assumed
responsibility for it, and continues to work with numerous parties to resolve all issues resulting
from the event. The Company does challenge the Agency’s enforcement response, however.
The Agency inspected the Company’s IMP program several times prior to the incident, and
found no violations related to the allegations in this NOPV. But once the incident occurred, the
Agency presumed that there must have been violations of the Part 195 regulations, and the IMP
rule specifically. That approach, and presumption, is not authorized by the PSA.

                                                            
24

Paragraph 1 relates to Item 1 of the NOPV; Paragraph 2 relates to Item 2; Paragraphs 3, 4 and 5 of the PCO relate
to Items 5 and 6 of the NOPV; Paragraphs 6 and 7 of the PCO relate to Item 8 of the NOPV; Paragraph 8 relates to
Items 3 through 7 of the NOPV, regarding documentation; and Paragraph 9 of the PCO is a non-mandatory request
for retention of cost records.

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No Strict Liability under the PSA
There is no strict liability provision in the Pipeline Safety Act to establish liability without fault
or causation. The Agency must prove that violations occurred, not simply that an accident
occurred. Although the Agency may be reluctant to acknowledge this, accidents can occur even
when an operator is in full compliance with the rules. This is one such accident. Even though
the Company was in compliance with the IMP rules in this instance, and no actionable anomaly
was reported by state of the art inspection tools at the point of rupture, the accident nonetheless
occurred.
EMPCo Complied with Applicable IMP Regulations
The core of the Agency’s allegations in the NOPV is that EMPCo failed to conclude that the pipe
segment in issue was susceptible to seam failure. Hindsight is indeed perfect, but the IMP
regulations only require that an operator consider the risk of seam failure on LF-ERW pipe, not
automatically conclude it. EMPCo did carefully consider the risk of seam failure on this
segment. The Company reviewed the issue multiple times over several years, and documented
its compliance with the rules on every occasion.
If the Agency’s core allegation regarding seam failure susceptibility is incorrect, then Items 1
through 4 of the NOPV, at a minimum, fail to state a claim. If the Agency’s core allegation is
upheld, however, then the entire industry and the public must now reconsider the Agency’s rules
and precedent regarding LF-ERW pipe. Nearly one quarter of all oil pipelines in the U.S.
contain LF-ERW pipe. If operators must now conclude that such pipe is automatically
susceptible to seam failure – without allowing for the evaluation and consideration process set
forth in the rules and used by all parties up to now – then the time and cost to implement that
conclusion could affect energy supplies throughout the U.S. Moreover, such a sweeping
characterization would undermine the public’s faith in PHMSA’s ability to monitor pipeline
integrity and safety in a logical and consistent, rather than a purely reactive manner.
As with most activities, it is not possible to predict and prevent all accidents. The Pipeline
Safety Act, and PHMSA regulations, establish a framework that requires careful identification of
threats, analysis of those threats, inspection methods designed to find problems before they
become manifest, and strategies to reduce and mitigate risks. That system has worked, as made
evident by the continually declining number and size of pipeline incidents over the past twenty
years.
Despite the success of the Agency’s pipeline integrity management program, some accidents can
occur even when an operator is in full compliance with the rules. In this instance, the Company
not only complied with the IMP rules, it did more than what was minimally required. Nationally
recognized experts (relied upon by PHMSA even in this proceeding) consulted with EMPCo on
its compliance with IMP rules before this incident occurred and their affidavits in this matter
lend strong support to the Company’s arguments. Even though the pipe was not deemed
susceptible to seam failure, the Company voluntarily ran the same tools and took the same risk
reduction methods beyond those required under the regulations. Significantly, an ILI seam tool
did not report any actionable anomaly at the point of rupture before the incident occurred. That
fact alone undercuts all of the government’s assertions in the NOPV.

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Neither a Penalty nor the PCO is Warranted
If the basic premise of the NOPV is wrong, then there is obviously no basis to assess any
administrative penalties against the Company. Even if the Agency’s alleged violations are
upheld, the penalty should be adjusted downward. Items 1 through 4 of the NOPV are so closely
related as to constitute a single violation, subject to a $1 million penalty cap. The other alleged
violations also depend on erroneous presumptions, not supported by the record. Instead of
applying mitigation factors in light of the Company’s cooperation, the NOPV erroneously asserts
that the Company made a conscious decision not to comply with the law, even while the
Company did more than the minimum required.
Similarly, if the substantive allegations of the NOPV are unfounded, then there is no basis for a
Proposed Compliance Order (PCO). The Company objects to the scope of the PCO, which
purports to apply to “all assets” of the Company, rather than just the pipeline at issue. That is
unusual, and unlawful. The Company contests that overly broad aspect of the PCO, but the
Company is also already pursuing the elements of the PCO, as it is EMPCo’s understanding that
the IMP rules properly read require continual evaluation and improvement, regardless of any
PCO. The public and the industry would be well served if the Agency used its resources to learn
from this incident, rather than to deflect concerns about application of rules, guidance and
available technology.
For all of these reasons, EMPCo respectfully requests that the NOPV be withdrawn, or
significantly revised in accord with applicable law and precedent.
Respectfully submitted,

_____________________________
HUNTON & WILLIAMS
Robert E. Hogfoss, Esq.
Bank of America Plaza, Suite 4100
600 Peachtree Street, N.E.
Atlanta, GA 30308
(404) 888-4042
Catherine D Little, Esq.
Bank of America Plaza, Suite 4100
600 Peachtree Street, N.E.
Atlanta, GA 30308
(404) 888-4047

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EXXONMOBIL PIPELINE COMPANY
Troy A. Cotton, Esq.
General Counsel
800 Bell Street
Houston, TX 77002
(713) 656-3783
Johnnie R. Randolph, Esq.
Counsel
800 Bell Street
Houston, TX 77002
(832) 624-7925
Date: June 2, 2014

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 Index of Attached Exhibits

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

No. Exhibit

1 Af?davit of John Kiefner (5/22/14)

2 Af?davit of Kent Muhlbauer (5/31/14)

3 M. Baker, Low Frequency ERW and Lap Welded Longitudinal Seam Evaluation. Chapter 4 
Figure 4.1 (April 2004)

4 IMP Manual Excerpts. Sections 4.4. 5.4 (2012)

5 OIMS Framework. Elements 2.4; 7.2 (2009)

6 OIMS System 2A, Attachment #1 Risk Matrix Methodology (rev?d 2004)

7 TIARA Manual. Section 8.0 (2007)

8 Memo regarding Corsicana to Patoka LSFSA (12/10/04)

9 Memo regarding Corsicana to Patoka LSF SA 10/05)

10 Management of Change Form No. 05-2829 10/05)

11 Management of Change Form No. 05-2833 10/05)

12 Metallurgical Analysis of Hydrotest Failures Excerpt Report No. 51708 (6/21/06)

13 TIARA Foreman to Conway UDT (6/26/06)

14 Corsicana to Patoka Slunmary of Hydrotest Leamings (7/06/06)

15 Hurst Metallurgical Analysis of Hydrotest Failures Excerpt Report No. 51763 (7/06/06)

16 IMP Integiity Assessment Data (IAD) Form 3.2 Foreman to Conway (7/26/06)

17 TIARA Foreman to Conway Manufacturing Threat Classi?cation (7/26/06)

18 TIARA Foreman to Conway Risk Assessment S1u11111ary(7/27/06)

19 Risk Assessment Slunmaries: Corsicana to Foreman. Conway to Doniphan, Doniphan to
Patoka (2006/2007)

20 IMP Preventive Mitigative Actions Form 61. Foreman to Conway (2007)

21 Foreman to Conway LSFSA and Pipelife Analysis Excerpts (2007)

22 Patoka to Corsicana LFSA Review (2009)

23 Email from NDT (8/23/10)

 

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No.

Exhibit

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

24 NDT Preliminary ILI Report Conway to Corsicana (received 8/23/10)
25 Repair Fonn PL-0751 MP 164.05 (8/28/10)

26 IMP Exception Form 1.2 (12/17/10)

27 Final NDT ILI Report Repair Stulnnary Conway to Corsicana Excerpts (2011)
28 TIARA UDT Conway to Corsicana (2011)

29 Conway to Corsicana LSFSA and Pipelife Excerpts (2011)

30 Email from NDT MP 142.39 Dig Sheet 10/ 1 1)

31 Repair Form PL-0751 MP 142.39 (1/12/11)

32 Repair Form PL-0751 MP 274.09 (1/13/11)

33 IMP Exception Form 1.2 (1/31/11)

34 Conway to Corsicana Manufacturing Threat Classi?cation (3/4/11)
35 Conway to oriscana IMP Form 3.2 IAD Form 15/ 1 1)

36 Conway to Corsicana Fonn 6.1 (7/21/11)

37 Conway to Corsicana EFRD Form 6.2 (7/21/11)

38 IMP Exception Form 1.2 (8/02/ 13)

39 IMP Exception Form 1.2 (8/28/13)

 

 

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Index of Exhibits Included bv Reference Only

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

No. Exhibit

40 Patoka to Corsicana 2005/2006 Hydrostatic Test Reports (MP 127-43 7)

41 Metallurgical Analysis performed by Hurst Report No. 409 l2-F (12/19/05)
42 LSFSA Foreman to Conway and Pipelife Analysis (2006)

43 Metallurgical Analysis performed by Hurst Report No. 41305 (4/20/06)

44 Metallurgical Analysis performed by Hurst. Report No. 41500 (4/24/06)

45 Metallurgical Analysis performed by Hurst Report No. 51695 17/06)

46 Metallurgical Analysis performed by Hurst Report No. 51708 (6/21/06)

47 Metallurgical Analysis performed by Hurst Report No. 51763 (7/6/06)

48 TIARA Foreman to Conway Risk Assessment (7/27/06)

49 TIARA Manual (2007)

50 Conway to Corsicana NDT MFL Combo ILI Final Report (2010)

51 Patoka to Conway GE PII TFI Final Report (2010)

52 LSFSA Conway to Corsicana and Pipelife Analysis (2011)

53 EMPCO 1MP Manual (2012)

54 Conway to Corsicana GE PII TFI Final Report (2013)

55 Hurst Metallurgical Investigation of Pegasus Pipeline Report No. 64961 MP 314 (7/9/13)
56 Pegasus Root Cause Failure Analysis Final Report Appendices 14)

 

 

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Hearing Sign-In Sheet

ExxonMobil Pipeline Company
CPF 4-2013-5027
June 11, 2014
Houston, TX

 

Name

Title

Organization

 

Benjamin Fred

Presiding Official

U.S. PHMSA

 

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1

Prepared for Release in PHMSA FOIA
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2

Prepared for Release in PHMSA FOIA

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PHMSA HEARING - June 11, 2014
ITMO ExxonMobil Pipeline Company, Pegasus Pipeline Incident (March 29, 2013) Mayflower, Arkansas

BEFORE THE
U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
IN THE MATTER OF

)
)
EXXONMOBIL PIPELINE COMPANY )
PEGASUS PIPELINE INCIDENT
)
(MARCH 29, 2013)
)
MAYFLOWER, ARKANSAS
)

CPF NO. 4-2013-5027
NOTICE OF PROBABLE
VIOLATION

******************************
PHMSA HEARING
June 11, 2014
******************************

PHMSA HEARING was taken in the above-styled and
numbered cause on June 11, 2014, from 8:27 a.m. to 12:19
p.m. before Roxanne K. Smith, Certified Shorthand
Reporter in and for the State of Texas, reported by
computerized stenotype machine at 8701 South Gessner,
Suite 1110, Houston, Texas.

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PHMSA HEARING - June 11, 2014
ITMO ExxonMobil Pipeline Company, Pegasus Pipeline Incident (March 29, 2013) Mayflower, Arkansas

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A P P E A R A N C E S

2

THE HEARING OFFICER:
3
4
5
6
7
8

Mr. Benjamin M. Fred
U.S. Department of Transportation
Pipeline and Hazardous Materials Safety
Administration
Office of Chief Counsel
1200 New Jersey Avenue SE, E26-308
Washington, D.C. 20590
Telephone: (202) 366-4346
Facsimile: (202) 366-7041
E-Mail: Benjamin.fred@dot.gov

9
10
11
12
13
14
15

FOR U.S. DOT'S PIPELINE AND HAZARDOUS MATERIALS SAFETY
ADMINISTRATION (PHMSA):
Mr. Rodrick M. Seeley, Director
U.S. Department of Transportation
Pipeline and Hazardous Materials Safety
Administration
Office of Pipeline Safety Southwest Region
8701 South Gessner, Suite 1110
Houston, Texas 77074
Telephone: (713) 272-2859
Facsimile: (713) 272-2831
E-Mail: Rodrick.m.seeley@dot.gov

16
17

FOR PEGASUS PIPELINE (OWNED BY MOBIL PIPELINE AND
OPERATED BY THE EXXONMOBIL PIPELINE COMPANY (EMPCo)):

18
19
20
21
22
23

Ms. Catherine D. Little
-andMr. Robert E. Hogfoss
Hunton & Williams
Bank of America Plaza
Suite 4100
600 Peachtree Street, N.E.
Atlanta, Georgia 30308
Telephone: (404) 888-4000
Facsimile: (404) 888-4190
E-Mail: Clittle@hunton.com

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PHMSA HEARING - June 11, 2014
ITMO ExxonMobil Pipeline Company, Pegasus Pipeline Incident (March 29, 2013) Mayflower, Arkansas

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A P P E A R A N C E S

2

(continued)

3

ALSO PRESENT:
4
5

PHMSA:

6

Ms. Molly Atkins, OPS Inspector, Accident
Coordinator for PHMSA Southwest Region
Ms. Mary McDaniel, Operations Supervisor for PHMSA
Southwest Region
Mr. Larry White, Counsel, PHMSA Headquarters
Mr. Cliff Zimmerman, Compliance Officer, PHMSA
Headquarters (VIA TELEPHONE)

7
8
9
10

ExxonMobil:

11

Mr. Troy Cotton, EMPCo, General Counsel
Mr. Johnnie Randolph, EMPCo Counsel
Ms. Johnita D. Jones, EMPCo Pipeline Risk and
Integrity Manager, Operations Department
Mr. Steve Koetting, P.E., Engineering Specialist,
Pipeline Integrity

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13
14
15

* * * * *

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PHMSA HEARING - June 11, 2014
ITMO ExxonMobil Pipeline Company, Pegasus Pipeline Incident (March 29, 2013) Mayflower, Arkansas

1

INDEX
PAGE

2
3

Appearances....................................

4

PROBABLE VIOLATION DISCUSSIONS:

2

5

Probable Violation 1......................

79

6

Probable Violation 2......................

132

7

Probable Violation 3......................

141

8

Probable Violation 4......................

142

9

Probable Violation 5......................

11

10

Probable Violation 6......................

32

11

Probable Violation 7......................

47

12

Probable Violation 8......................

54

13

Probable Violation 9......................

69

14

Reporter's Certificate.........................

166

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16
17

* * * * *

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19
20
21
22
23
24
25
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PHMSA HEARING - June 11, 2014
ITMO ExxonMobil Pipeline Company, Pegasus Pipeline Incident (March 29, 2013) Mayflower, Arkansas

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(Proceedings commence at 8:27 a.m.)

2

THE HEARING OFFICER:

Good morning.

Thank

3

you-all for attending.

4

concerning the Notice of Probable Violation issued by

5

the Office of Pipeline Safety Southwest Region to

6

ExxonMobil Pipeline Company.

7

November 6th, 2013.

The issue was issued

The CPF number is 4-2013-5027.

The notice alleged nine violations of the

8
9

This is the informal hearing

pipeline safety regulations, proposed civil penalties of

10

approximately $2.6 million and proposed a compliance

11

order.

12

My name is Ben Fred.

I'm the presiding

13

official at today's hearing.

I'm an attorney in PHMSA's

14

Office of Chief Counsel.

15

official for pipeline safety enforcement hearings.

I am the designated presiding

16

I'll give some brief remarks about how

17

today's hearing will transpire and how the case will

18

proceed after today's hearing.

But first, let's begin

19

with a round of introductions.

We'll start over here.

20

MS. LITTLE:

Sure.

Catherine Little,

21

counsel with ExxonMobil Pipeline Company with

22

Hunton & Williams law firm.

23
24
25

MR. HOGFOSS:

Bob Hogfoss,

Hunton & Williams law firm for ExxonMobil.
MR. KOETTING:

Steve Koetting, pipeline

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PHMSA HEARING - June 11, 2014
ITMO ExxonMobil Pipeline Company, Pegasus Pipeline Incident (March 29, 2013) Mayflower, Arkansas

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integrity specialist for ExxonMobil Pipeline.
MS. JONES:

2
3

integrity manager for ExxonMobil Pipeline Company.
MR. RANDOLPH:

4
5

MR. COTTON:

MS. MCDANIEL:

MS. ATKINS:

14
15
16
17
18
19

Molly Atkins, accident

investigator, PHMSA.
MR. WHITE:

12
13

Mary McDaniel, operations

supervisor, PHMSA.

10
11

Troy Cotton, general counsel

for ExxonMobil Pipeline Company.

8
9

Johnnie Randolph, counsel

for ExxonMobil Pipeline Company.

6
7

Johnita Jones, risk and

Larry White, serving as OPS

counsel.
MR. SEELEY:

Rod Seeley, director for

PHMSA Southwest Region.
THE HEARING OFFICER:

And Cliff, can you

introduce yourself?
MR. ZIMMERMAN:

Cliff Zimmerman,

compliance officer at headquarters.

20

MR. WHITE:

I'll sign in for Cliff.

21

THE HEARING OFFICER:

Thank you.

Now,

22

some brief procedural remarks, PHMSA's regulations

23

authorized this hearing and specified the manner in

24

which it will be conducted.

25

C.F.R. Section 190.211.

Those regulations are in 49

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PHMSA HEARING - June 11, 2014
ITMO ExxonMobil Pipeline Company, Pegasus Pipeline Incident (March 29, 2013) Mayflower, Arkansas

Today's hearing will be conducted

1
2

informally, which means we'll not be required to follow

3

any specific rules of evidence or rules of procedure.

4

Each party will have time to speak without interruption

5

to make sure that we give each side enough time to cover

6

everything that they'd like to present.

7

appropriate point, we can engage in some back-and-forth

8

discussion.

And then at the

This hearing is being recorded and will be

9
10

transcribed for the record.

You will note that I'll

11

also be taking notes during today's hearing.

12

are for my use later on in the case, which I'll get to

13

in a second.

14

official record.

My notes

My notes are not made a part of the

As the presiding official, my role is

15
16

two-fold.

First, I'll regulate the course of the

17

hearing today to make sure we cover everything in a fair

18

and efficient manner.

19

positions of the parties today in anticipation of

20

preparing a recommended decision in this case.

21

second role is after the hearing is over and after any

22

additional materials are submitted to me, I'll be

23

preparing a recommended decision in the case, which is

24

forwarded to the Associate Administrator for Pipeline

25

Safety who will issue the Agency's decision called a

I'll also be listening to the

So, my

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PHMSA HEARING - June 11, 2014
ITMO ExxonMobil Pipeline Company, Pegasus Pipeline Incident (March 29, 2013) Mayflower, Arkansas

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final order.
The final order will make findings as to

2
3

whether each of the alleged violations were proved; and

4

if so, will specify the terms of any civil penalty

5

and/or corrective action.

6

regulations, the Regional Director will be submitting a

7

post-hearing recommendation to me.

8

Region's recommendation.

9

stated here today impartially, as well as everything

Under our procedural

I'm not bound by the

I'll consider everything

10

submitted in written materials when I prepare my

11

independent recommended decision.
Upon issuance of the final order, our

12
13

regulations permit the Respondent to petition for

14

reconsideration of the final order within 20 days of

15

receipt, and that's provided for in 49 C.F.R. Section

16

190.243.

17

today and how the case will proceed after today's

18

hearing.

19

So, that's how the hearing will be conducted

Some quick housekeeping matters.

We're

20

getting started right on time at 8:30.

So, we'll plan

21

for a break at 10:00 o'clock or so; but that's flexible

22

depending on how things are going.

23

have a break for lunch.

24

hearing today will last as long as it needs to to make

25

sure we cover everything, but usually I ask in the

And then we'll also

I will -- we will -- the

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PHMSA HEARING - June 11, 2014
ITMO ExxonMobil Pipeline Company, Pegasus Pipeline Incident (March 29, 2013) Mayflower, Arkansas

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beginning if anyone has any afternoon travel plans that

2

we should try to meet or if people's schedules are open.

3

Okay.
Finally, Mr. Seeley, it's your turn to let

4
5

everyone know where the facilities are and emergency

6

exits.
MR. SEELEY:

7

For those who are not

8

familiar with us, for the facilities, the restrooms, if

9

you go out our main entrance, if you take a left,

10

they're down the hallway.

In the case of an emergency

11

where we have to evacuate the building, the stairwell is

12

just beyond the restrooms.

13

down to the first floor, exit the building and head

14

down.

15

know where we'll be going.

16

street and congregate at one of the corners.

We would take that stairwell

Best thing is just to follow us since you don't
But we'd go down to the

There is a break room down on the first

17
18

floor.

You have to go out security, and they have

19

snacks and sodas and whatnot.

20

in our little kitchen there.

21

coffee there because I don't drink coffee, but they

22

have all your snacks and drinks downstairs if you

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want.

We have a water bubbler
I don't know if there's

24

THE HEARING OFFICER:

Okay.

25

Has everyone signed in?

Thanks.

Great.

Before we

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PHMSA HEARING - June 11, 2014
ITMO ExxonMobil Pipeline Company, Pegasus Pipeline Incident (March 29, 2013) Mayflower, Arkansas

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get started, does anyone have any opening remarks before

2

we start talking about the individual items?

3

MR. SEELEY:

We do not.

4

THE HEARING OFFICER:

Okay.

Did you have

5

a preference on the order in which you wanted to cover

6

the items?
MR. HOGFOSS:

7

Well, actually, we were

8

going to suggest that after PHMSA makes its opening

9

remarks and we do a very short version of ours, that in

10

the interest of time efficiency, since the first issue

11

of the nine and really Items 1 through 4 will likely

12

engender the most of the discussion, we thought perhaps

13

if the Region agrees, we could talk first about Items 5

14

through 9.
And then on all of the items, again just

15
16

to make this as productive as possible, we thought we

17

will state, you know, our position on an item and then

18

encourage the Region to actually discuss it item-by-item

19

instead of coming back, because we may all have

20

forgotten some of the things we've said by the time we

21

get through all of the nine.

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THE HEARING OFFICER:

23

understand, you wanted to talk about 5 through 9

24

individually.

25

MR. HOGFOSS:

Okay.

So, if I

Yes.

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PHMSA HEARING - June 11, 2014
ITMO ExxonMobil Pipeline Company, Pegasus Pipeline Incident (March 29, 2013) Mayflower, Arkansas

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THE HEARING OFFICER:

2

MR. HOGFOSS:

3

And then --

And then 1 through 4

individually.

4

THE HEARING OFFICER:

5

MR. HOGFOSS:

Okay.

And then I guess we

6

conclude with just some comments on penalties but at

7

each point.

8

opening statement, we thought we can just go

9

item-by-item.
THE HEARING OFFICER:

10
11

Instead of making one very long essentially

a problem with that.

I don't have

Start through items 5 through 9?

12

MR. SEELEY:

13

THE HEARING OFFICER:

14

Okay.

That's fine.
Okay.

Would the

Region care to introduce Item 5?
MR. SEELEY:

15

Yeah.

I'll briefly introduce

16

it.

17

the stuff that's already been submitted to the case file

18

and to the violation report.

19

I'm not going to present all of the evidence and

But Item 5 of the notice relates to the

20

operator failing to take prompt action to address

21

anomalous conditions on the pipeline.

22

with some ILI runs where there were some immediate

23

conditions identified.

24

and review of records, it -- the records did not

25

indicate that the prompt action required an immediate

This has to do

And through our investigation

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PHMSA HEARING - June 11, 2014
ITMO ExxonMobil Pipeline Company, Pegasus Pipeline Incident (March 29, 2013) Mayflower, Arkansas

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condition was taken.

2

THE HEARING OFFICER:

3

MR. HOGFOSS:

Thank you.

Okay?

Would you like us -- well,

4

to begin with, just on behalf of ExxonMobil Pipeline

5

Company, we do thank all of you for coming, especially

6

Ben and Larry who traveled.

7

at the outset that the Company understands this was a

8

very significant incident.

9

responsibility for the incident from the outset, has

And we would like to note

The Company took full

10

cooperated with the Agency, with many agencies,

11

continues to cooperate, continues to work with the

12

federal government, the state government and many other

13

parties.
And the Company does not see this matter,

14
15

the PHMSA administrative violations, as much of a

16

monetary penalty issue as a larger question about how

17

the integrity management program rules, the IMP rules,

18

really are intended to apply.

19

the theme that you have seen in our pre-hearing

20

materials and you'll hear again today.

21

you for attending this hearing and engaging on these

22

issues.

23

And so, that's -- that's

But we do thank

So, to -- and I guess a final thing just

24

to note is that these are -- and we noted this in our

25

pre-hearing materials -- these are legal issues.

The

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PHMSA HEARING - June 11, 2014
ITMO ExxonMobil Pipeline Company, Pegasus Pipeline Incident (March 29, 2013) Mayflower, Arkansas

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nine items are alleged violations of PHMSA's regulations

2

and/or the Company's IMP procedures, which have the

3

force of regulation.

4

very complex factual record that the Region knows well,

5

and the issues are known well to both the Agency and the

6

industry.

So, they're legal issues.

It's a

But ultimately what we're looking at is

7
8

that the Agency has made alleged violations.

The burden

9

is on the Agency to establish those violations; and our

10

responsibility is, where appropriate, to challenge the

11

elements of the claim to see if they're met.

12

our focus; and we will try to be as efficient as we can.

So, that's

As to Item 5, we think this one is really

13
14

an issue where the allegations are simply incorrect,

15

that you just looked at the wrong data.

16

as Rod said, was that on two occasions at two different

17

mile markers, the Agency [sic] failed to declare a

18

discovery.

19

in-line inspection tool that needed some type of repair

20

in a timely manner in accordance with the IMP

21

regulations.

22

items called out were a long way away from the Mayflower

23

incident

They failed to identify an anomaly from an

We should note that both of these two

itself.
So, this is really more about how the IMP

24
25

The allegation,

program works.

Both of these cases we think if you look

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PHMSA HEARING - June 11, 2014
ITMO ExxonMobil Pipeline Company, Pegasus Pipeline Incident (March 29, 2013) Mayflower, Arkansas

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at the actual record -- and correct it -- and we

2

understand when you're putting together the NOPV, you

3

don't have as much time to look at all of the data as

4

you may have later.

5

inform [sic] some of this.

6

two -- these two anomalies were actually classified

7

properly within two days of receipt of information, and

8

they were both repaired within five days.

9

through both of them.

And so, the passage of time helps
But in both cases, these

So, let's go

10

The first one was at milepost 164.051.

It

11

was reported to the Company in a preliminary report.

12

So, the IMP rules allow 180 days from the completion of

13

the tool run to declare discovery where practicable, the

14

rule says.

15

report on August 23, 2010 -- and that's shown in

16

materials in Exhibits 23 and 24 -- and it was shown to

17

be a 72 percent wall loss.

18

you can look at Exhibit 25 -- is that the Company

19

declared it an immediate repair anomaly the same day

20

that it received the information and repaired it five

21

days later.

In this case, they did get a preliminary

Well, the irony here -- and

22

So, we think if you look at Exhibits 23,

23

24, 25, you'll see that for milepost 164.051, that, in

24

fact, the Company did timely declare discovery, did

25

promptly act on it; and we think that should be
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ITMO ExxonMobil Pipeline Company, Pegasus Pipeline Incident (March 29, 2013) Mayflower, Arkansas

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withdrawn.
MS. LITTLE:

2

And the confusion I think

3

that was presented in the NOPV is there's a document

4

that is a vendor document, not a document that was dated

5

with a vendor date, not the date that the preliminary

6

report was provided to ExxonMobil Pipeline.

7

August 9th date that was included in the NOPV.

8

you even look at the next NOPV item number, Number 6, it

9

notes the date the preliminary report was received,

That is the
But if

10

which is the date that ExxonMobil received that

11

information, which is the August 23rd date that Bob just

12

referenced.

13

MR. HOGFOSS:

So, actually the NOPV itself

14

corrects itself.

15

date; whereas, Item 5, the allegation there.

16

Catherine said, you know, we can understand how the

17

wrong date was transposed.

18

the NOPV's own table on Item 6 and then looking at the

19

exhibits we referenced, this should make clear that this

20

one actually was both identified and properly classified

21

and repaired in a prompt manner.

22

And Item 6, it does show the proper
And as

But I think in looking at

So, the second item alleged in -- the

23

second example alleged in Item 5 was milepost 142.394.

24

And that one was not called out in a preliminary report,

25

but it was only noted for the Company in the final
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ITMO ExxonMobil Pipeline Company, Pegasus Pipeline Incident (March 29, 2013) Mayflower, Arkansas

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report that is received from the vendor.

And you can

2

see that in Exhibit 30 of our materials.

It was

3

received on January 10, 2010.

4

of an anomaly.

5

corrosion pit.

It was really a much less

It was a 0.74 percent top dent with a

The anomaly was repaired two days later on

6
7

January 12th.

That's shown in Exhibit 31.

Again, here

8

in the Pipeline Safety Violation Report, there are

9

documents cited regarding a different anomaly than

10

alleged in the NOPV; and you can see that in Exhibit 32.

11

The other -- the Exhibit 23 anomaly is a different

12

milepost, and that one was an immediate repair.

13

information was received on January 10 and repaired on

14

January 13th.

That

15

So, at bottom, we're saying that both of

16

these, we think it was just a mistake of fact in terms

17

of looking at them and thinking that they were not

18

properly and timely classified when, in fact, we think

19

that the record shows that they should be corrected.
Any other comments from our side?

20

Is it

21

okay if we -- I mean, we're okay to just discuss this

22

now.

23

back.

Or, Rod, if you want to wait; and we can come

THE HEARING OFFICER:

24
25

Do you have any

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PHMSA HEARING - June 11, 2014
ITMO ExxonMobil Pipeline Company, Pegasus Pipeline Incident (March 29, 2013) Mayflower, Arkansas

MR. SEELEY:

1

This seems to be -- we don't

2

want to get confused with the discovery versus the

3

action.

4

it seems to be a controversy, if you will, over reports

5

and dates; and I will turn to Molly to discuss her

6

records and what she reviewed, where she got her dates

7

from, compare and see where the differences are.

This is more of the action on the anomaly.

MS. ATKINS:

8
9

And

The primary information that

we looked at that caused us to ask questions was the

10

repair reports, and the discovery date and repair date

11

through most of the reporting were the same or one day

12

apart.

13

the records we have, for example, in your Exhibit 25 on

14

the third page, it says discovery was 8/27 and repair

15

was 8/28.

So, while the discovery may be somewhere else,

The information that we relied upon is the

16
17

preliminary report.

Initially we had the date of 8/23

18

as being received; but when we requested a copy of the

19

preliminary report, it had the date on it of August 9th,

20

I believe --

21

MS. LITTLE:

And, again, I think --

22

MS. ATKINS:

-- the vendor date.

23

MS. LITTLE:

It was a vendor date in the

24

underlying document of the vendor -- their date.

25

wasn't the date received by the Company.

That

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MS. ATKINS:

1

So, when we looked at the

2

e-mail in Exhibit 23 of your brief, the e-mail states,

3

"Today is the day he wanted them sent to him."

4

experience has been normally the information is

5

available and shared over the telephone or at some point

6

in the process as soon as the vendor has it and has that

7

information.

8

was affected by pressure and it was less than a pressure

9

[sic] of one.

Our

And while it was 72 percent, it said it

So, the information that we have was not

10
11

so much the determination or classification as

12

immediate; but it is those other actions that must be

13

taken, such as a pressure reduction or a shutdown until

14

the repair can be made.

15

on the same day that the repair is made, it would appear

16

that those actions for pressure reduction or shutdown

17

are not being taken.

18

information as to whether or not a pressure reduction

19

was taken.

20

And when discovery is declared

But at this point, we have no

So, without any other information other

21

than the records to rely upon, it would appear that for

22

discovery and repair to occur on the same date and

23

different than the dates of the information being

24

available to the Company, that the response actions are

25

not just classifying it; but it is to take that
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immediate pressure reduction or shutdown until the

2

repair is made.
MR. HOGFOSS:

3

If I could just ask two

4

questions.

5

noted where we see some discrepancies could have come

6

in, some misreading of it that you don't see the points

7

that we're making.
I guess my question is, Catherine said the

8
9

So, the exhibits we pointed out, I think we

August 9th date was a vendor date.

And vendors in the

10

real world do not actually provide all of the

11

information; and it is a major issue for both the Agency

12

and the industry if you don't necessarily get all of

13

your information on time.

14

it's worth looking at Exhibit 30, just as an example;

15

and it's a series of e-mails.

In fact, if you look at --

16

And look at the third page in Exhibit 30

17

near the bottom, and there's an exchange there with an

18

EMPCo representative sending a pretty strongly worded

19

message back to an ILI vendor saying, Look, you just

20

gave us a final report and for the first time called out

21

some immediate repairs.

22

with this.

23

on in the next paragraph to say this is simply not --

24

you know, we do not like surprises like this.

25

And we are not at all pleased

This is not what we expect.

And it carries

That's just an example of how it actually
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1

occurs, that there is frustration.

2

issue, frankly, with they -- you know, the way it's

3

supposed to go.

4

better than I can.

5

you know, the Agency expects is an ILI tool vendor, as

6

they're getting their data and should be looking and

7

letting their company know when to work on immediate

8

repairs.

9

go that way.

10

There is a vendor

And Steve or Johnita can address this
But the way it's supposed to go, as

It usually goes that way.

It doesn't always

And then also the rules require that, you

11

know, you give 180 days to find this.

12

always get their reports to companies within 180 days,

13

which is why the rule which we can remember personally

14

from when the IMP rules came out, that the comments and

15

the discussion at the time, there was concern back in

16

2000, 2001, [sic] were there enough ILI tools out there

17

to implement IMP.

18

Vendors don't

I think that's progressed to 12 years

19

later from the effective date of the rule to there's not

20

that many vendors, and they are very difficult

21

contractually to try and force -- frankly, ultimately,

22

this is beyond the issues in this hearing -- but it

23

would be helpful if the Agency could promulgate some

24

rules that apply to vendors to be more prompt.

25

that's an example of -- in response to your comment that

But

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what we see as the Company -- when the Company gets the

2

information, they act on it.
MS. ATKINS:

3

We don't take any exception

4

to immediates being identified in a final report.

We

5

understand the correlation with the metal loss tools has

6

to occur and that usually occurs after the preliminary

7

report with the analyst being able to correlate the two

8

runs.
But the issue is that the date of the

9
10

repair in your exhibit shows discovery and repair on the

11

6th, which is before the final report is stated to be

12

received.

13

but the records that we had to rely upon show repair

14

that in your tab -- and, again, it was 31 labeled on

15

January 12th.

16

Page 3 that the repair and discovery for January 6th.

17

And you state that the final report was received on the

18

10th.

19

Page 3 of that exhibit actually shows discovery date of

20

1/5 and repair date of 1/5.

21

date of 1/12, where the number of five has been

22

scratched out and amended.

23

So, again, it may be a record-keeping issue;

Let me find that exhibit -- it shows on

So, those dates don't match.

The Exhibit 31 and

Yet, the front page has a

The other one which may have been the

24

immediate, which is under Tab 32, is the one that shows

25

discovery and repair 1/6.
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MR. HOGFOSS:

1
2

The Exhibit 32 is the --

that's where the violation report --

3

MS. ATKINS:

4

MR. HOGFOSS:

5

We were pointing that out.

6

milepost.

Uh-huh.
That's the wrong anomaly.
That's at a different

That's at 274.091.
MS. ATKINS:

7
8

anomaly.

9

discovery and repair.

It was the intent that be the

In either case, they both show the 1/6 and 1/5

MR. HOGFOSS:

10

Again, we're just going back

11

to the NOPV.

What's written in the NOPV were these two

12

mile markers.

And as we were trying to understand the

13

basis for the alleged violation, we noted that there was

14

this confusion of different mile markers.

15

you're now saying the intent was this other mile marker

16

in Exhibit 32, then, in fact, that was also timely

17

classified and repaired.

18

MS. ATKINS:

Yes.

And so, if

I think my point was

19

the date of discovery and repair are the same but prior

20

to receipt of the final report on the 10th.

21

discovery and repair to occur on the same day, you're

22

declaring discovery in the ditch, not --

23

MR. KOETTING:

24

MS. ATKINS:

25

MR. KOETTING:

And for

In some cases we do.
-- prior to that.
In some cases we do.

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MS. ATKINS:

1

So, you have information

2

ahead of time that caused you to call this an immediate.

3

So, the response is to take an immediate pressure

4

reduction or shut down the pipeline for immediate

5

conditions.

6

was determined it was immediate?

7

coincide means it's being declared immediate in the

8

ditch, not in the office.

9

reports to qualify it as an immediate and take those

10

So, at what point are you saying that it
For those two dates to

So, you're not using the

actions.
So, the actions that we expect for

11
12

immediates is that you receive the information.

13

make a determination about it meeting criteria for

14

immediate or not.

15

examination.

16

actions prior to, as in your procedures say that you

17

must take immediate pressure reduction.

And then they go out and do the

And that immediate triggers additional

So, in the code and in the procedures,

18
19

You

that is the expectation for an immediate condition.

20

MS. LITTLE:

Let's go back.

21

MS. ATKINS:

And that's the part that I

22

can't find.

23

taken, maybe you could demonstrate that through a record

24

of a pressure reduction.

25

If there was, in fact, a pressure reduction

MS. LITTLE:

The NOPV Item itself, if we

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1

look back at what the allegations are in NOPV Item 5,

2

what you-all note in here is that the operator failed to

3

take prompt action, failed to declare discovery from

4

information received in preliminary reports.

5

first example that you use, the 164 -- milepost 164.051

6

and milepost 142.394, the way in which the allegation

7

reads is that both sites were identified as immediate

8

repairs from the preliminary report that was received on

9

August 9.

And the

And then you note that the operator didn't

10

identify them as immediate repairs until the sites were

11

excavated, the first one being 19 days later and the

12

second one being several months later.

13

way in which -- you're speaking just on different issues

14

now in terms of --

And I think the

15

MS. ATKINS:

The immediate response --

16

MS. LITTLE:

-- what we want to see.

17

MS. ATKINS:

I'm sorry.

18
19

I didn't mean to

interrupt you.
MS. LITTLE:

That's okay.

No, I'm just --

20

to bring us back to what the allegation says, when we

21

look at milepost 164.051 -- and I think as the documents

22

we provided demonstrate -- that was not received -- that

23

information, the preliminary report, was not received

24

until August 23rd; and it was declared an immediate on

25

that same day upon receipt of that preliminary report
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1

and repaired five days later.

2

in the ditch, as you said.

3

MR. HOGFOSS:

So, that was not declared

So, we have a -- again, as

4

Catherine's saying, we're looking to the alleged

5

violations in the NOPV; and we thought as we looked into

6

this, this just seems clearly to be just a mistake, a

7

transposition of dates, which is understandable given

8

all of this information.

9

be a simple matter of just correcting and saying, gosh,

10
11

So, this -- these two seem to

looking at the right documents -MR. SEELEY:

Just to help me out.

We

12

apparently have a record that shows an August 9th date.

13

Your assertion is that that receipt of that report was

14

actually August 23rd.

15

MS. LITTLE:

16

the cover letter in our --

17

MR. HOGFOSS:

That's right, and we include

And the Company provided

18

that letter to you, but it was misconstrued that the

19

Company had possession of that on August 9th.

20
21
22

MR. SEELEY:
between August 9th?

What is the discrepancy

Does an August 9th report exist?

MS. LITTLE:

There's a August 9 date on a

23

document that the vendor maintained and was part of the

24

documents that came with the preliminary report.

25

is the vendor's August 9 date that refers to something

But it

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1

the vendor was doing on that day.

But all of that

2

material was transmitted to the Company on August 23rd.

3

It was --

4

MS. ATKINS:

The transmittal --

5

MS. LITTLE:

-- not transmitted to the

6

Company on August 9th.
MS. ATKINS:

7

The transmittal indicates

8

that that is the date he requested it be delivered to

9

him.
MS. LITTLE:

10
11

I'm not sure I understand your point.
MS. ATKINS:

12
13

How can they hold it if it's

available prior to that?

14

MS. LITTLE:

15

MR. HOGFOSS:

16

you're talking about?

17

it --

18

They have to set deadlines.

I'm not sure it was.
Can you point to a document

Again, the Company didn't receive

MS. ATKINS:

It's your transmittal cover

19

letter in the exhibit.

And that's the first time I've

20

seen that because I was just provided the report.

21

so, the transmittal says that is the day that he

22

requested it be sent in the e-mail.

23

that exhibit, Exhibit 23, Page 2, "Here are the

24

preliminary files for the ExxonMobil job.

25

forward them to Chris Gorman after your review.

And

So, we go back to

Please
Today

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1

is the day he wanted them sent to him."

2

MS. LITTLE:

To me that means the deadline

3

and the date they were expected to be provided.

4

know why that would suggest anything differently.

I don't

5

MR. SEELEY:

Okay.

So --

6

MS. LITTLE:

It takes them a long time to

7

pull together all the information, we know that, the

8

vendors.
MR. SEELEY:

9

So, your date record which

10

would indicate August 23rd is delivery of the report,

11

you've declared this anomaly to be an immediate; and

12

then your actions were five days later.

13

action between the 23rd and the 28th?
MS. LITTLE:

14
15

that same day.

Did you do any

Declared it an immediate on

Scheduled and undertook to repair --

16

MR. SEELEY:

So, your immediate --

17

MS. LITTLE:

-- that took place in five

MR. SEELEY:

-- action was five days

MS. LITTLE:

The repair was declared

23

MR. SEELEY:

I asked were there other

24

actions -- I guess maybe I'll rephrase.

25

other actions taken between the 23rd and the 28th where

18

days.

19
20

later.

21
22

immediate.

Were there

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1

I'm assuming you made some sort of mechanical fix?
MR. KOETTING:

2
3

right on the site.

We had to scramble.

MR. SEELEY:

4

The crews are not located

I'm not talking about

5

mechanical fix.

6

take any other immediate action like a pressure

7

reduction or something that is actionable without a

8

mechanical fix?

9

correct?

10

I'm talking about an action.

Did you

The repair is a mechanical fix,

So, I'm asking:

Are there other actions that

the operator took between those two dates?
MS. JONES:

11

Our program makes an analogy

12

between an unvalidated preliminary report and an

13

immediate repair and a safety related condition.

14

have five days to validate that report and then five

15

days to fix it.

16

discussion internally when we receive that report and

17

begin to take those steps as if it were a safety

18

condition.

19

five days.

So, we

And so, we immediately convene a

So, we repaired it within that very first

MS. ATKINS:

20

So, the record shows here the

21

discovery date of 8/27 and repair date of 8/28.

22

you're saying the discovery and declared an immediate

23

was the 23rd?

24

MS. JONES:

25

MR. KOETTING:

But

Yes.
This is a 72 percent.

We

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1

had a tool tolerance to determine that it was

2

possibly -- we've been criticized for that.

3

particular case, we don't know if it's -THE HEARING OFFICER:

4
5

This

Can you speak up

just a tad?
MR. KOETTING:

6
7

by the vendor 72 percent.

8

immediate.

On its face, that is not an

MS. ATKINS:

9

The anomaly was called out

What was the actual?

10

MR. KOETTING:

11

MS. ATKINS:

12

MR. KOETTING:

The actual is 90 percent.
Okay.
So, going beyond what the

13

regulation required by adding tool tolerance to it.

14

We've been criticized for this before.

15

declaring immediates because you're adding tool

16

tolerance to anomalies.

17

did it properly.

18

and it, in fact, it did turn out to be greater than

19

90 percent.

20

it immediate with the call or is it immediate when we

21

actually determine it's immediate?

22

up and it was actually 60 percent, that's not an

23

immediate.

24
25

You guys are

In this case it turned out we

We excavated and got people out there

So, there's always this confusion about is

Because if we dug it

So, this whole point of discovery has to
do with what does it actually turn out to be.

So, in

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this case, it did turn out to be immediate.

2

goodness that we acted on a preliminary report that

3

showed it less than that.

4

action.

5
6
7

MR. SEELEY:

Thank

I think we took prompt

I don't think we have any

other unique points to make.
MS. ATKINS:

What we were looking for is

8

the action until the repair was made, which is what code

9

states, a pressure reduction or shut down for immediates

10

until the repair can be made.

11

something we need to look at the procedure and see what

12

your procedure at that time said because it has changed

13

since that time frame.

14

is different today than it was in 2010.

15
16
17

And so, that may be

I know that immediate response

MS. JONES:

And that procedure has been

looked at numerous times.
MR. HOGFOSS:

We won't -- so much for

18

trying to be time efficient.

It's only Number 5.

We

19

won't belabor this, but what we'll say for a wrap on

20

this one, is that the allegations in Item 5, when we

21

look to them, we see that they're incorrect.

22

match the actual record in terms of dates and mileposts.

23

And as Steve just said in terms of this first example

24

given, it actually did not meet in the preliminary

25

report criteria in the rules for an immediate.

They don't

So, you

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know, we can address that in our post-hearing submittal.

2

But clearly I guess we leave this one unresolved.

3

Now, to --

4

MR. WHITE:

5

Item 5 before we move to the next one?

Can I make one last point on

6

THE HEARING OFFICER:

7

MR. HOGFOSS:

8

No.

Were you done?

I was going to say

we're ready to move on to Item 6.
MR. WHITE:

9

I just want to say that I can

10

understand that the 23rd -- taking the 23rd as the day

11

that the repair was done five days later and the

12

regulation calls for immediate action.

13

just want to point out that, you know, this -- this

14

case, it happened to be five days.

15

next time it might be 10 days.

16

be 15, 20 days.

And so -- but I

But, you know, the

The next time it might

17

I mean, we have to -- we have to -- the

18

concern, I guess, for the Agency would be it can be a

19

sort of slippery slope.

20

folks, when they come into that situation as we've got a

21

preliminary report calling something out as immediate,

22

is start looking -- they're looking for immediate

23

action.

24

brought.

25

did take prompt action.

And so, I think what these

So, I can understand why the allegation was
I can understand why the Company feels that it
But I just simply say that, you

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know, we -- I think the Agency has to worry a little bit

2

about -- you know, we don't want to get into sort of a

3

line drawing exercise here.

4

the reason why the inspectors were sort of -- this would

5

catch their attention.
MR. HOGFOSS:

6

But I think that's sort of

And this is a term that we

7

will discuss often today.

But hindsight is perfect, and

8

this is a minor example of it, that, yes, knowing what

9

you know once it was dug and examined, it was an

10

immediate.

The preliminary report didn't classify it as

11

an immediate.

12

so, that's another postscript.

13

all of us have to deal with the facts presented the way

14

they are.

So, the Company treated it as that.

And

You have to deal with --

15

But we are ready for Item 6 if you want.

16

THE HEARING OFFICER:

17

MR. SEELEY:

Okay.

Item 6.

Item 6 has to do with

18

declaring discovery within the 180-day time frame.

19

There is a table in there -- I'm not going to go through

20

it -- where it points out several ILI runs and it

21

articulates the 180-day deadline.

22

we reviewed, we list their dates of discovery from what

23

we can tell.

24

requirement that was in the regulation.

25

And the records that

And they all exceed the 180-day

THE HEARING OFFICER:

Thank you.

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MS. LITTLE:

1

Okay.

Back to discovery for

2

this one as well.

3

four different occasions where the Agency believes that

4

the Company failed to declare discovery.

5

as we've demonstrated in the brief -- and we can talk

6

about here -- in each one of those instances, the ILI

7

data wasn't received from the vendor until very nearly

8

the end of the 180-day period from when the pig hit the

9

trap.

10

Just as you said the Item 6 cites to

And I think,

In one case I think it even was provided after, I

think in one instance.
So, in all of those cases -- and the regs

11
12

allow for a company to claim that a period is

13

impracticable in certain instances to meet the 180-day

14

time period.

15

nearly the end of the 180-day period and you still have

16

to verify that data and allow time for data integration

17

to make sure you've got good data and make the judgment

18

calls you need to make as an operator.

19

When you don't get the vendor data until

It's simply not possible when you have a

20

negative time frame because the data came after the

21

discovery or you're in a very tight time frame.

22

rules and procedures that the Company has in place under

23

IMP allow for that, there's a process that's set forth

24

that the Company follows as to when you can say

25

something is impracticable.

The IMP

And in each of those cases,

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you know, they looked and followed the rules, the

2

regulations that the Agency had promulgated.

3

followed their own procedure and revised the discovery

4

deadline as a result of the fact they could not complete

5

the tasks that were necessary to complete within the

6

time frame.

They

We put in our brief a figure, Figure 4,

7
8

that shows the dates that the final report was received

9

when the 180-day deadline was originally to run and when

10

the deadline was revised.

11

it shows final report as being very near the deadline.

12

So, I think the Patoka to Conway MFL-Combo tool, and TFI

13

tool -- the tool run was completed on August 15th.

14

the final report was not received until the very end of

15

December in 2010.

16

order to be able to do the data integration and do the

17

verification of the data.

18

from I think originally -- the 180-day deadline was

19

supposed to be February 11th, and they extended it to

20

March 11th.

21

And in each instance, the --

And

And they requested an extension in

So, they extended discovery

For the Conway to Corsicana section, the

22

MFL-combo tool which completed its run on July 21st, the

23

final report was not received until January 7th, 2011

24

and the 180-day deadline was ten days away.

25

extended the discovery there for the same reasons and

So, they

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practicability as allowed for under the rules and

2

procedure until March 17th.
And then lastly, the TFI tool for Conway

3
4

to Corsicana, that run was completed on February 6th.

5

The date of the final report was August 29th, and that

6

was well after the 180-day deadline of August 5th, 2013.

7

So, again, they extended the period there.

8

case, we think they followed the rules and followed the

9

Agency's guidance and followed their own procedure

10

In each

manual.

11

THE HEARING OFFICER:

12

MR. SEELEY:

Thank you.

Well, I guess it comes down

13

to what one would consider impracticable under the

14

regulations, and the regulations are written and

15

interpreted or implied very many ways.

16

been consistent is you have 180 days which includes the

17

vendor reports to be received.

18

operator has to be aware of and take care of, and it's

19

not something you can use as an impracticability issue

20

when the vendor doesn't supply that to you.

21

One of which has

And that's something the

Also, what other processes you add to a

22

review also has to be considered in that 180 days.

23

That's been consistently stated from the Agency so you

24

have to include that within your 180-day.

25

process, plus the operator's report, has to be within

So, your

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the 180 days.

That's not something you can use as an

2

impracticability argument from the Agency's perspective.
I think that's what I've heard you say,

3
4

and we would primarily just disagree with that as being

5

an impracticality argument in this case.

6

different ways you could -- to address it if you have a

7

situation.

8

probably get your reports out shorter.

9

the data process works, but I didn't hear any arguments

You can segment your runs differently,

10

over the actual dates within the record.

11

discrepancy of the dates?

12

MS. LITTLE:

13

There are many

I don't know how

Did I hear

Of the dates that you-all

have in there.
MR. SEELEY:

14

We're not arguing over dates

15

at this point.

16

of -- I think the argument seems to be stemmed on the

17

impracticability issue?

18

They are what they are.

MR. HOGFOSS:

It's a matter

I think that's right.

I

19

think on the Figure 4, we did supplement it by showing

20

the actual receipt of the report.

21

MS. LITTLE:

Right.

22

MR. SEELEY:

Is this the preliminary

23

report that's in the table now or is that a different --

24

so, we have that data in our notice as well.

25

MR. HOGFOSS:

Yes.

So, it's not an issue

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of dates.

But it is an issue and we do take issue with

2

the concept of the impracticability.

3

that was added to the IMP regulation was because of the

4

reality that -- and the Agency does not always tell

5

operators that it's a violation if their vendor gets

6

them the data late.

Because the reason

That's the whole reason the process is in

7
8

the IMP rules, that exception in the rule; and the other

9

provision in the IMP rules to when you need to make an

10

exception to your IMP program, you need to explain it,

11

document it and have a good reason.

12

was done in all four of these instances where the vendor

13

got [sic] the data late.

14

Exhibit 30 which was a contemporaneous showing of where

15

the Company is expressing great displeasure to the

16

vendor for getting them information late, but it

17

happens.

In this case, that

And we already referred to

It happens not just with this company but

18
19

with the industry.

And the rules allow for that.

They

20

say when that happens, we hope it doesn't happen that

21

often, industry and agency.

22

with it.

Don't make a practice of it.

23

it does.

We think in this case it was provided for in

24

the rules.

25

think it does meet the exception of the rule.

This is how you should deal
Document it when

The Company followed the process, and we

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MS. LITTLE:

1

Johnita, do you want to talk

2

a little bit about the internal process that you-all go

3

through?

4

the deadline --

It's not an easy process if you want to get

MS. JONES:

5

The internal process for an

6

exception to the 180-day requirement requires us to go

7

all the way to the vice president of the Company.

8

take it that seriously.

9

boss, the vice president.

We

So, it has to go to actually my
We ask that the engineer

10

who's doing the analysis to give us plenty of time to

11

have those discussions, and it's not a very last-minute

12

type activity.

13

case when you get the reports very late, it is very

14

difficult to do discovery within that 180-day time

15

frame.

So, we do recognize, especially in this

16

MS. ATKINS:

17

MS. JONES:

18

Is that your Form 1.2 MOC?
It's not the MOC.

be the exception.

19

MS. ATKINS:

20

MS. JONES:

21

(Simultaneous colloquy.)

22

MS. ATKINS:

23

It should

Exception?

So, 1.2.

I can --

I'm sorry.

I'm just having a

hard time myself.

24

MS. JONES:

I call it the exception.

25

MR. KOETTING:

That sounds right.

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MS. JONES:

1

There will be an exception for

2

each one of these forms to forward to the manager for

3

approval.
MS. ATKINS:

4

Do you recognize that there

5

are things that the operator can do to cut down that

6

delivery time?

7

indicate that they cannot meet the specification dates

8

because of the size of the runs.

And the communications with the vendor

In particular in our violation report,

9
10

Exhibit C, we have a copy of the communications between

11

Jeff Johnson at PII and Chris Gorman where he states in

12

April of 2012, which is well before the run is performed

13

which began in July 2012 and was completed in

14

February 2013, "Our proposal states 90 days for the

15

first 50 miles, 30 days for every 50 miles thereafter,

16

resulting in 258 days."

17

that he couldn't meet discovery.

He told you before the tool run

So, these actions of combining, which we

18
19

have it on another item to discuss later, we were

20

talking about the length of the segments and management

21

of change impacting things to -- regulatory requirements

22

as well, need to be evaluated.

23

separate item.

24
25

And so, that's a

But in this particular item, it is not
impracticable when something is designed that cannot be
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1

achieved.

And when the vendor tells you they can't

2

achieve it ahead of time and you experienced it on

3

repeated occasions, it should be something that you're

4

well aware of for the data analyst time and the amount

5

of anomalies on these lines that they have to evaluate.
So, the careful evaluation that they

6
7

perform for you does take time and the careful

8

evaluation that you must do to see is it an HCA, is it

9

something that's already been repaired?

There's a lot

10

of process that goes on and we recognize that.

11

days is a safety issue for the freshness of the data to

12

be reviewed that is timely and changes occur that

13

further impact and degrade that anomaly.
MS. LITTLE:

14

But 180

I think -- just to respond to

15

that a little bit, I think there are some other issues

16

you've raised that are unrelated to NOPV Item 7 and to

17

keep us focused on NOPV Item 7, which is about the

18

180-day period.

19

MR. SEELEY:

6.

20

MS. LITTLE:

I'm sorry.

Thank you.

21

Item 6 -- gosh, feels like we should be on 7.

22

6.

23

NOPV

NOPV Item

And I think you were talking about the

24

communications with the vendor.

And, remember, the

25

discovery time frame runs from the date that the tool
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1

hits the last trap.

So, he may be saying in those

2

e-mails -- and I don't have them in front of me -- but,

3

you know, the point being that discovery runs from when

4

it hits the last trap.

5

e-mails talk about about the length of time, the 180-day

6

period doesn't begin until the tool comes out.

So, irrespective of what those

MR. SEELEY:

7

I think the part of the

8

conversation is the operator has some control -- and

9

this goes back to the impracticability claim as well.

10

You have some control over what you're asking someone to

11

do.

12

significantly long doesn't [sic] allow the meeting of

13

the deadline is in your control where you could have and

14

should have shortened those segments so you could have

15

met the 180-day discovery by all communications we have

16

seen.

So, to create a situation where the tool run is

If you hadn't combined segments or, in

17
18

other words, had you kept the segments separated, you

19

could have made the shorter segments meet the deadline

20

as required.

21

longer segment, which made it -- resulted in them not

22

meeting the 180 days.

23

and vendor's control and communication.

But instead, the operator chose to have a

That was totally in the operator

24

So, it was a choice to have such a long

25

segment; and that's not an impracticability argument.
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1

That's a business choice.

2

MS. ATKINS:

Further, in this TFI run, the

3

first segment was run in July of 2012; and the

4

completion time for the 180-day clock didn't start until

5

February 6th, which in itself was more than 180 days

6

after the first tool was removed from the trap.
In reviewing the 2012 version of your

7
8

integrity management program where it says the last tool

9

run of the series of runs is when you start the clock,

10

these runs occurred between July 2012 and February of

11

2013.

12

separation and tool dates greater than one month.

13

haven't seen that justification.

14

Justification should be provided for any
I

But we agree that when it comes out of a

15

trap, that is when the clock starts.

16

particular case, no data was requested from the vendor

17

until all tool runs were completed, which further

18

exacerbated the problem of meeting that time frame in

19

that the 180-day clock started in February, not in July

20

when the tool run was actually completed.

21

spaced over a period of time of July, September and

22

February, which are all more than a month.

23

two, I believe, in September because there were four

24

significantly separate tool runs.

25

And in this

And the areas were not rerun.

Those were

There were

The data

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was not recollected, and the data that was used from the

2

initial run in July is what was analyzed later.

3

process of discovery was significantly delayed because

4

the dates shown here of the TFI run when you received

5

the final report August 29, '13 is more than a year

6

after when the tool was removed from the trap.
MR. HOGFOSS:

7

So, the

Respond in part to that in

8

something Rod said.

I think the Region knows well from

9

industry generally that problems with vendors getting

10

late reports to companies is really not limited to the

11

length of segment.

12

it's a problem with the industry.

13

sees it occurring.

14

should be to have problems with getting reports, putting

15

aside, Molly, the issue of when -- what you call a tool

16

run and when it is concluded.

It's an unfortunate fact that -We know the Agency

It's not -- it's not as rare as it

The vendors -- there's two separate

17
18

issues.

One is pressing a vendor to provide at least

19

timely reports of what may be immediate conditions as

20

the run's progressing regardless of segment length, and

21

that is done, and to get a final report in a timely

22

manner.

23

this item for the NOPV, first of all, you have four

24

examples.

25

sitting there.

And it's a larger problem -- the allegations in

And this is -- don't have a hundred examples
And the exhibits show that the Company

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1

was being diligent in pursuing the information.
We think it's frankly a selective use of

2
3

the Agency of trying to find an instance where you could

4

read in delay [sic] when, in fact, we think that the

5

Company dealt with the reality and problems created by

6

vendors in these situations and acted in accordance with

7

both the IMP rule and its own procedures.
MS. ATKINS:

8
9

So, if the vendor tells you

they can't meet the 180 days prior to performing the

10

inspection, you've got knowledge to deal with ahead of

11

the inspection being performed.
MR. KOETTING:

12
13

That would be an

impracticality.
MR. HOGFOSS:

14

My understanding was the

15

vendors will not tell you that, but they also won't

16

commit to the -- they won't be responsible for failing

17

to meet the 180 days, which frankly is something we need

18

help on.
MS. ATKINS:

19
20

e-mail.

22
23
24
25

I think that was my point.
MR. SEELEY:

21

They told you that in this

I think we've covered all of

our -MR. KOETTING:

It's very difficult to make

discovery when you haven't received the report.
MS. ATKINS:

We agree.

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MR. KOETTING:

What are we to discover

2

within 180 days?

We try very hard to get our reports.

3

Sometimes successful; sometimes not.

4

MR. SEELEY:

5

MR. KOETTING:

6
7
8
9

I think we've -That's the definition of

impracticability.
MR. SEELEY:

I think we've covered all the

unique points on this.
MS. ATKINS:

Just for your reference, I

10

can provide -- this is our violation report, Exhibit C.

11

It's an April 16th, 2012 e-mail chain between Jeffrey

12

Johnson and Chris Gorman.

13

MS. JONES:

14

MS. ATKINS:

I'm sorry.

The date?

April 16th, 2012.

And it

15

goes back -- there's several e-mails back and forth that

16

is in our Exhibit C to the violation report.

17

MS. JONES:

I guess the only thing I would

18

add would be from the time frame that we got that e-mail

19

to when we were putting that tool in the line, it is not

20

practical for us to go back and change the segment.

21

that would require additional trap installation and

22

modifications out in the field to do that.

23

April 16th when we started the tool runs, that

24

physically cannot be done.

25

MS. ATKINS:

So,

So, between

In retrospect, you ran it in

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four separate sections, four discrete segments run in

2

that inspection.
MS. JONES:

3

There's one point they're

4

inserted, and one point to take it out.

5

MS. ATKINS:

That's correct.

But your

6

records to us and your e-mail -- would you like me to

7

pull that one?

8

MR. SEELEY:

I think we can finish up.

9

MS. ATKINS:

Okay.

10

MR. SEELEY:

I think we've pointed it out.

11

MS. ATKINS:

Okay.

12

MR. RANDOLPH:

And one other point on

13

that, it's important to realize for that 2013 TFI, the

14

line was shut down when the discovery was done.

15

know, the vendor themselves had a lot of attention on

16

this issue because they had been -MR. SEELEY:

17
18
19

The line was shut down for

what?
MR. RANDOLPH:

They had -- the vendor had

20

actually held the data longer and reanalyzed and

21

reanalyzed because there had been a release.

22

So, you

MS. ATKINS:

We did ask for -- we did ask

23

for them to look at additional data and provide

24

preliminary data in that very location.

25

their efforts, but that doesn't take away from that

That took away

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first segment in July of 2012 that had not had the data

2

looked at that was in the failure section.
THE HEARING OFFICER:

3
4

MR. HOGFOSS:

I think we agree to disagree

on that.
THE HEARING OFFICER:

7
8

Anything else

on Item 6?

5
6

Okay.

Okay.

We'll move on

to Item 7 then.
MR. SEELEY:

9

Okay.

Item 7 is an

10

allegation that the operator failed to follow its own

11

IMP procedures.

12

extending the timing of some -- some risk analysis,

13

talks about Section -- or your Section 5.4, which

14

requires risk assessments to be updated as changes

15

occur.

16

allegation is the analysis was delayed, which -- without

17

proper justification and, therefore, you did not follow

18

your procedures.

This has to do with the operator

And without going into all the details, the

19

THE HEARING OFFICER:

20

MR. HOGFOSS:

Yes.

Thank you.
And as we acknowledge,

21

and we stated before, the IMP regulations do require

22

operators to develop their own procedures to implement

23

the IMP rules.

24

require a course of law.

25

Plan Section 5.4 and Operational Integrity Management

And those procedures, we acknowledge, do
So, this is our procedure, IMP

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Systems (OIMS) Section 2.4 at issue.

The footnote here,

2

which we will come back to when we get to Item 1, but

3

the Item 1 of the NOPV alleges, it goes back to that the

4

Company should have concluded that a seam tool was

5

required to have been run.
So, this Item 7 is premised on that

6
7

assumption.

8

any event, but it presumes that a tool run, a crack tool

9

run was required.

10

Just to note, we will respond to it now in

Ironically, the Company did elect to

voluntarily run a TFI seam/crack tool.
And so, that's -- this allegation is that

11
12

you didn't -- you delayed running it when you should

13

have.

14

risk assessment which led to a failure to consider

15

preventive and mitigative, P&M measures.

16

disagree with this on two levels.

17

believe that a tool run was required, a crack tool; and

18

we'll come back to that.

19

And because of that delay, you didn't update your

So, we

One is that we don't

But the Company actually did revise its

20

risk assessment in March of 2011.

It was scheduled to

21

be reviewed again in 2013, which is a conservative

22

reassessment interval.

23

would occur that would affect the risk assessment in

24

this time; and most significantly the tool -- the

25

seam/crack tool was run.

There had been no changes that

Unfortunately for all parties,

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it didn't detect a reportable anomaly.
So, our position actually is that the

2
3

Company exceeded part 195 IMP rule requirements here by

4

voluntarily running a crack tool.

5

violate those requirements.

6

simple logic that kind of undercuts the allegations of

7

Item 7, which is this, is that when the crack tool was

8

run, allegedly late, but when it was run in 2012, 2013

9

there was no actionable anomaly found at the point of

It clearly didn't

And ultimately there's some

10

rupture.

Because crack growth in this type of pipe is a

11

time-dependent thread, it's pure logic the crack could

12

have only been smaller and less detectable if it was run

13

when you allege it should have been run.
So, it's -- it would not have been

14
15

discovered by an earlier tool run, and that's the

16

ultimate irony in this allegation.

17

because we don't believe it was required to be run at

18

that time.

19

detect an anomaly.

20

minimum requirements here.

21

We disagree with it

The Company did it in any event, didn't
We think the Company went beyond the

MR. SEELEY:

If I may interrupt one

22

point -- and I don't want to -- I want to try to see if

23

I can refocus the discussion.

24

the tool run conversation.

25

to do with is the risk analysis that is to perform.

We're tending to go into

And what this allegation has

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There's a risk analysis that it was to

1
2

perform.

There was a risk analysis that was performed

3

which at the time assumed a tool run was going to be

4

run.

5

analysis wasn't revised and updated to incorporate that

6

information, which it had assumed would be done didn't

7

get done.

8

reflect that the assumption that was made before

9

actually never occurred.

That tool run didn't occur, and then the risk

So, the risk analysis never got revised to

I don't want to get into the

10

actual assessment being run or haven't been run.

11

the risk analysis portion that wasn't updated based off

12

of information that was assumed and eventually never

13

occurred.

14
15

MR. HOGFOSS:

It's

But there were no changes in

the input to that risk analysis.

16

MS. ATKINS:

Yes, actually there were.

17

MR. SEELEY:

If you assume something to

18

occur in your risk analysis and that didn't occur, there

19

is a change that has to be done in your analysis because

20

the assumption put into it never occurred.

21

to go back and say it didn't occur.

22

MR. HOGFOSS:

So, you have

But for the length of time

23

it was allegedly delayed, there was no change that would

24

affect a variable in a meaningful way.

25

MS. ATKINS:

Actually Item 8 will address

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the impact of the results in the TIARA model and how

2

it's used.

3

and extending that from the assumption made that it

4

would be run in 2011, it changes the risk score and it

5

changes the identified threats.

6

Item 8.

7

tool in the TIARA questions in the input, there were no

8

identified threats through this area.

But in making that change to the analysis

And we cover that in

But because the answer was yes, we ran a crack

Had the run which was done for both cases

9
10

of yes or no to that answer, [sic] there were identified

11

threats that resulted, which did require management

12

notification in accordance with OIMS.

13

running the tool in 2011 and extending it, you change

14

the risk by not having identified threats.

15

management notification and mitigation, if necessary,

16

because the risk profile changed because the tool -- it

17

may not have even been appropriate to say yes at the

18

time it was stated in the original run because it had

19

not, in fact, been run at the time the risk analysis was

20

done.

21

discuss in Item 8 -- to use yes as the answer and make

22

the manufacturing threats go away.

23

So, by not

Then require

There was a conscious choice to -- which we'll

MR. HOGFOSS:

Molly, if the tool run was

24

run when you allege it should have been run, do you

25

believe it would have found the anomaly?
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MS. ATKINS:

1
2

have.

That's not the question we

That's not the allegation.
MR. HOGFOSS:

3

Isn't that really the

4

ultimate issue here, though, is that you're faulting the

5

Company for failing to take certain actions at certain

6

times that you apparently believe would have prevented

7

this incident?
MS. ATKINS:

8
9

The allegation in Item 7 is

that there was a change in the conditions and the

10

assumptions made in the risk profile and the risk model

11

was not updated.
MR. HOGFOSS:

12

Right.

And our response to

13

that is we don't believe it was required to have been

14

done.

15

legal requirement.

16

there been -- run earlier, affected the ultimate

17

outcome.

18

difference.

So, there was a change that didn't affect the
And ultimately there was -- had

So, it's really a distinction without a
But we'll save it, Item 1 or Item 8.
MS. LITTLE:

19

I think also -- and, Steve,

20

correct me or Johnita if I'm incorrect -- but I think

21

that when they were doing the TIARA analysis, they

22

actually ran it both ways, right, to see -MR. KOETTING:

23
24
25

We ran multiple scenarios

to see -MS. LITTLE:

Can you speak to that?

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MR. KOETTING:

2

MS. LITTLE:

Right.

3

MS. ATKINS:

We'll discuss that under Item

4

-- if anything changes.

8.

5

MR. KOETTING:

6

MS. LITTLE:

Okay.

7

MR. SEELEY:

Are we going to Item 8?

8

MS. LITTLE:

Did you want to add

MS. ATKINS:

We can come back around to

9

this one after we've talked about Item 8 maybe.
MR. KOETTING:

12
13

One last thing on Item 7,

the process that we followed -THE HEARING OFFICER:

14
15

It's Item 8.

something?

10
11

Yeah.

Sorry.

Can you

repeat your statement?
MR. KOETTING:

16

The process we followed to

17

determine whether or not to run a seam tool made the

18

determination that it wasn't susceptible to long seam

19

failure by the process that we adopted that was

20

published.

21

don't know how it changes an answer on the risk

22

assessment.

23

the insinuation that the risk model drove the decision

24

to run the tool was invalid.

25

decision.

And, therefore, if it wasn't susceptible, I

It would change that determination.

So,

It didn't change the

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1

Your TIARA model doesn't

2

determine whether or not you want to run the tool.

It

3

determines a level of risk and identifies risk that then

4

has followup actions in your procedures.

5

identified threat there is identified -- and I think

6

that's when we're getting into Item 8 -- there's certain

7

things you need to do.

8

those actions don't happen; and the risk reduction

9

measures, whatever they are, don't occur.

So, if an

And so, if that doesn't occur,

So, in this particular case, it's not

10
11

about whether or not you ran a tool.

12

answered the question in the risk model and when the

13

questions answer changed, because really it was answered

14

wrong in the first place, it didn't get updated and

15

actions didn't get taken, whatever those actions might

16

be.

17
18

THE HEARING OFFICER:

It's how you

Anything else on

Item 7 before we move on?

19

MR. HOGFOSS:

Nothing.

20

THE HEARING OFFICER:

21

MR. SEELEY:

Okay.

Okay.

Item 8.

Well, quickly so we

22

can get to the conversation, Item 8 is the operator

23

failed to follow the procedures which has to do with

24

their TIARA model, failure to --

25

THE HEARING OFFICER:

Can you -- that

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acronym?
MR. SEELEY:

2
3

TIARA stands for threat

identification and risk assessment.

4

THE HEARING OFFICER:

5

MR. SEELEY:

And we've already started the

6

discussion on it.

7

and let the discussion continue.

9

So, I'm just going to step off there

THE HEARING OFFICER:

8

Thank you.

Molly, did you have

anything you wanted to add?
MS. ATKINS:

10

The TIARA model was run

11

with -- there's a set of questions that are asked.

And

12

one of the questions is in the risk assessment or the

13

TIARA question process, was a crack tool run.

14

answer is either yes or no, and there's a different

15

score in the risk profile.

16

model, and the -- it's a combination.

17

risk model, and TIARA has a user manual for it [sic].

And the

This is the Muhlbauer risk
It's the EMPCo

And it indicates that, yes or no, it's a

18
19

different weighting and elevates the risk if it's no and

20

it's a lower risk if it's yes.

21

answering no, there were identified threats.

22

identified threat is a threat that is local to a

23

segment.

24

testable segment, it's the subsegment in there.

25

purpose for that is to not have the entire weighted

When they ran it by
An

Instead of the entire weighted average of the
And the

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average outweigh the small segments that might have high

2

risk but are then discounted because of the weighting

3

process.
So, when these identified threats become

4
5

apparent, there is a requirement to follow the OIMS

6

guideline for management notification.

7

it in the TIARA manual.

8

believe, for your risk processes in OIMS.
MS. JONES:

9

It doesn't state

It says OIMS 2A process, I

I'm not sure that the OIMS 2A

10

specifically speaks to notifying management of an

11

individual threat.
MS. ATKINS:

12
13

you that it does.
MS. JONES:

14
15

The TIARA manual instructs

It comes out as the final

scores from the risk assessment.
MS. ATKINS:

16

So when the crack tool was

17

run with no, there were moderate identified threats in

18

the results.

19

no threats.

20
21
22

And when it was run with yes, there were
The communications that were provided -MR. WHITE:

I'm sorry.

Can you point out

which exhibit you're reading?
MS. ATKINS:

These would be our Exhibit B;

23

and they also have Bates stamps, if you'd like, from

24

the EMPCo [sic].

25

materials provided, and I can read the Bates stamps.

They'd also be in Exhibit A in all the

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MR. WHITE:

1

And you're looking at this

2

document at the top, manufacturing threat

3

classification.

4

MS. ATKINS:

5

MR. WHITE:

6

MS. ATKINS:

7

10

And it has a list of mile -Beginning stations and ending

stations between Conway to Corsicana.
MR. WHITE:

8
9

Yes.

Okay.

And then we have the

same record for the scenario where the answer was yes in
the model.
MS. ATKINS:

11

That's correct.

There are

12

communications in an e-mail dated 3/14/2011 between

13

David Martin and Chris Gorman, both with ExxonMobil.

14

And this also would be in our Exhibit A and Exhibit B

15

that said, "Go ahead and upload the risk assessment with

16

the D3 score and no manufacturing threats so it's

17

representative of the pipeline going forward."

18

"With the crack tool answered yes it also comes out a D3

19

probability...and all the threats in manufacturing went

20

away."

21

It says,

So, by choosing to represent that there

22

was going to be a tool run -- it was expected only to be

23

a couple months after this assessment.

24

2011, and it was expected that the tool runs would be in

25

the summer of 2011.

This is March of

There was a reasonable expectation

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to represent it as if that tool run were being

2

performed.

3

further delayed after that, they didn't go back and look

4

at should we do anything with these threats.

5

not revise their TIARA runs, their output, because this

6

assumption was changed in the Management of Change form.

7

That goes back to Item 7.

8

discussing, Item 7.

However, when it was delayed a year and then

They did

That's the part we were

9

In Item 8, the fact that there was a

10

choice to say no and use these results selectively

11

allowed for there to be no action and no additional

12

threat reduction, risk reduction taken in this area when

13

instead of saying yes -- excuse me -- instead of saying

14

no, they said yes in the questions; and the identified

15

threat went away.

16

And as a result all the further

17

processes -- these are, again, the Exhibit -- they're in

18

Exhibit A and Exhibit B of our violation report -- if

19

there are no threats identified, the process stops.

20

all of these subsequent actions in the emergency flow

21

reduction, leak detection and preventative and

22

mitigative measures will stop.

23

MR. WHITE:

Okay.

And

This one here, what

24

you're referencing as a flowchart or a decision tree

25

from ExxonMobil's own procedures.

Is that right?

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MS. ATKINS:

1

These are the IMP figures

2

6.2, 6.3 and 6.5.

3

there are no subsequent actions to reduce risk.

4

result of not identifying that threat was to not take

5

any additional action.
MR. KOETTING:

6
7

MS. ATKINS:

So, why did we run the

Your risk assessment is not

the decision for running the tool.
MR. KOETTING:

10

Exactly.

11

understand our risk assessment process.

12

MS. ATKINS:

13

And the

tools then?

8
9

If no threats are identified, then

Okay.

You don't

Well, possibly you

could explain to me -MR. KOETTING:

14

When we do risk assessment,

15

it's supposed to be done, preventative and mitigative

16

activities.

17

changed inputs?

18

What you're saying, answering yes and no to

19

manufacturing risks, demonstrates how sensitive is our

20

risk assessment model for the inputs, which is, should

21

we run the seam assessment tool or not.

22

We're trying to do what-ifs.

What if we

What -- would that change the risk?

We had already made the decision to run a

23

seam assessment tool.

The TIARA process that you're

24

saying changes the answers from yes to no, see how it

25

affects it, feeds right into that.

It says yes.

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This -- running this seam assessment tool will reduce

2

the manufacturing threat.

3

to run it.

So, that drives our decision

It's not that we used the risk assessment

4
5

to justify not running the tool.

6

assessment to justify running the tool, even though the

7

seam failure susceptibility analysis is not susceptible.

8

So, you've got it backwards.

9

running the tools by saying yes.

10

We used the risk

It's to help us justify
If we -- if we run a

tool, it will result in a risk reduction.
MS. ATKINS:

11

My observation of your form

12

6.2, 3 and 5 in the data integration all start with no

13

threat identified in the TIARA model and as a result, no

14

subsequent risk reduction or evaluations were taken.

15

And that is part of the post-assessment processes that

16

you go through that must occur within a year after the

17

tool is run.
So, it's not just the decision to run the

18
19

tool.

20

that statement and further risk and preventative and

21

mitigative measures, if you need additional valves, if

22

you need to look at leak detection.

23

into all your other processes for the risk management,

24

not just the tool selection.

25

It's what you do with the risk information for

And so, that feeds

In looking at these decisions, it affected
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the way other decisions were made.

2

the beginning says, the purpose of the identified threat

3

is not to mask a high-risk short segment over the

4

long -- longer testable segment.

5

MR. KOETTING:

6

MS. ATKINS:

Your TIARA manual in

Yeah, it does.
Well, it does if you don't

7

identify the threat.

The highest consequences were in

8

these areas in this segment which all had a one- or

9

two-consequence level, which is the highest in your risk

10

level.

Yet, the overall weighted one was three.

11

nowhere would that consequence be evaluated with the

12

probability if you don't elevate the probability for a

13

manufacturing risk to create a failure and combine that

14

high consequence with that probability to show that

15

elevated threat level.

16

in your model.

And that's what failed to occur

MS. JONES:

17

So,

We ultimately made the

18

decision based upon the data from the model as well as

19

the information and knowledge of the people who work the

20

pipeline to schedule additional installations to protect

21

the area.

22

MS. ATKINS:

23

MS. JONES:

24

MS. ATKINS:

25

Have you installed those?
They have not been installed.
So, when did you make that

decision?
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MS. JONES:

2

MS. ATKINS:

I don't know.
Those are not installed?

The

3

first recommendation from the data integration team to

4

run a TFI tool came in 2009 for 2010.

5

that you should run a TFI tool with the combo tool in

6

your 2010 assessment.

7

again to 2012.

8

without this threat, I agree, said you need to run a

9

crack tool.

That was then delayed to 2011 and

So, the data integration team even

MS. JONES:

10

They said in 2009

I think that will get back in

11

our arguments in 1 through 4.

12

frame that was given with that recommendation for

13

running that.
MR. HOGFOSS:

14

There was also a time

And also, we're really

15

drifting off what the allegation was in Item 8 at this

16

point, which is understandable.

17

But if I can step back for a second, unfortunately, for

18

a legal analysis of this.

They're all related.

This allegation -- and as we said at the

19
20

outset, this is a complex matter.

There's a lot of

21

material.

22

Report, the investigation report throws a lot of

23

material out there.

24

issues, it's disconcerting that when we point out an

25

alleged fact discrepancy, suddenly the topic shifts to

The NOPV, the Pipeline Safety Violation

But as we're discussing these

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something else; and it just happened in this Item 8.
So, let's step back to the beginning of

2
3

Item 8.

The allegation in Item 8 is made under 49

4

C.F.R. Section 195.402(a).

5

says, Each operator should have an operator, an

6

operations and maintenance, an owner manual.

7

manuals shall include [sic] -- address normal

8

operations, abnormal operations, emergency operations.

402(a) is one sentence.

It

The

The one paragraph allegation in NOPV Item

9
10

8 says that EMPCo failed to follow its O&M manual by

11

selectively using its TIARA risk assessment process.

12

would actually like Ben to consider when this case is

13

before you, Ben, a motion to dismiss this item for

14

failure to state a claim.

15

brought under 195.452(b)(1).

16

the rules that says have a written IMP plan that part of

17

which is where this TIARA comes from.

18

important.

We

Frankly, it should have been
That's the provision of

So, it's

19

I mean, you can throw everything against

20

the wall, all these facts; but, in fact, you've thrown

21

nine darts against the wall, nine alleged violations of

22

law.

23

violations, not [sic] every time you have an answer,

24

suddenly the topic moves and we're talking about a

25

different issue.

We're here today to address those alleged

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So, specific to the allegation in Item 8,

1
2

did the Company violate its own O&M procedures?

Well,

3

we're not talking about O&M procedures.

4

about TIARA.

5

of talking about the facts you want to talk about -- and

6

we do have to postpone until we get back to Item 1,

7

because we strongly believe that we were not required to

8

get into this time loop that you're talking about.

9

But the Company's doing more than is

We're talking

And then when we get to the point, then,

10

minimally required, which the Agency encourages the

11

industry -- that's the whole purpose of IMP.

12

These are your minimal requirements of, really, part 195

13

in its entirety.

14

required.

15

the fact that this company on every one of these issues

16

has done more than required.

It says,

We want you to do more than what's

We wish the Agency would at least acknowledge

So, on to allegations within Item 8, when

17
18

it says that you failed to consider impacts at Lake

19

Maumelle, that's wrong.

20

TIARA.

21

measures.

22

the rules don't require that in a certain time.

23

guess we're just -- we're troubled with not only the way

24

that this claim is stated, but then the allegations that

25

make -- again, defy logic because the Company did all

The Company did go through

They did go through OIMS.

They did identify P&M

They are putting in EFRDs.

And as you know,
So, I

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the things that you're saying it should have done.
And, again, ultimately would any of those

2
3

as you allege have identified this anomaly?

And the

4

answer is no, which becomes very significant when we get

5

back to Item 1.

6

should have done that in the Region's assessment would

7

have avoided this incident, in fact, would not.

8

that should be our shared goal, is that we're all

9

looking for ways, how can we implement the rules, how

10

can we push technology to find these type of defects.

11

And, you know, that's what we frankly are looking for;

12

and that's what we know the Region is, too.

13

we're trying to get to some common ground.

But all the things you say the Company

And

And so,

We understand that the Agency as a whole

14
15

has a need to respond publicly to significant incidents.

16

But there's another way to do it, to be to push --

17

frankly, we'll get to it -- but what the post-incident

18

Battelle study has encouraged as well, as well NTSB has

19

encouraged.

20

apologize.

But now I'm getting off Item 8.

MS. ATKINS:

21

So, I

I'm sorry for digressing from

22

the subject.

I was responding to questions.

But our

23

allegation of the selective use and the communications

24

that were underlying that would lead us to be concerned

25

that the results resulted in the full risk assessments
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and evaluation not being carried through and developing

2

appropriate preventative/mitigative actions.

3

just the tool run itself.

4

for the studies that are conducted after the assessment

5

and data integration, those activities.
MR. WHITE:

6

It's not

It's the additional things

Mary, do you have any thoughts

7

about just sort of this general issue of what integrity

8

management's assessments, the issue of individualized

9

threat, in other words on a stretch of HCA, which could

10

be X length within an overall tool run?
And do you -- is it your opinion that it's

11
12

consistent with ExxonMobil's procedures that this --

13

they're talking about an overall decision they've made

14

to do the tool run in its entirety.

15

that it's consistent with ExxonMobil's procedures to

16

sort of -- in this -- in this decision to not include

17

this identified risk on these discrete HCA portions?

18

you feel that they acted inconsistent with their

19

procedures?

20

MS. MCDANIEL:

But do you feel

Do

Well, I think the way that

21

these two violations are, the first one is once they

22

said they were going to run a tool and they didn't, they

23

didn't get the risk analysis in the time frame, it did

24

affect that two-year time frame when you intended to do

25

a tool run for whatever reason and then you didn't do it
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until two years later.

In that interim period, you

2

should have considered the other risk factors and

3

threats in the EFRDs and other things that are using

4

that -- choosing the other answer, that other route.

5

And I think that was the basis for the first one.

6

then the second one would be based off of the reasons

7

you made those selections.

8

inconsistent from what your procedure says.
MS. ATKINS:

9

And

So, I think that was

Your TIARA manual that you

10

have in your Tab 7, your Exhibit 7, states in the last

11

paragraph before Section 8.1, because of the length

12

weighting, it is possible for an identified threat to be

13

present and the testable segment -MR. WHITE:

14
15

Can you describe what

you're reading from?
MS. ATKINS:

16
17

Sorry.

Sure.

Reading from Exhibit 7

of the hearing brief from ExxonMobil.

18

MR. WHITE:

19

MS. ATKINS:

Okay.
And it is Page 120 of the

20

TIARA model.

It is the last paragraph before Section

21

8.1 under risk assessment driver determination.

22

Because of the length weighting of the

23

model, it is possible for an identified threat to be

24

present and the testable segment risk level to be low.

25

To ensure that identified threats receive appropriate
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management notification and action, any testable segment

2

with an identified threat is treated at a minimum as a

3

low or moderate risk.

4

action taken is to be completed in accordance with OIMS

5

System 2A procedures.

Management notification and

If the identified threat is chosen to go

6
7

away, if there's a choice that it goes away in the

8

process, then those follow-on actions do not occur.
MR. WHITE:

9

Is that -- I think we've

10

pretty much summed up our position.

11

any -MR. SEELEY:

12

Rod, do you have

I think we've got our -- I

13

think we've covered this issue; and we'll confuse it

14

again with the next one, I'm sure.

15

THE HEARING OFFICER:

16

have any comment to the assertion that the wrong

17

regulation was cited for this item?
MR. SEELEY:

18

Let me ask:

Do you

I don't believe -- I think

19

402 covers all of the operation and maintenance, and

20

integrity is part of the operation and maintenance of a

21

pipeline.

22

applicable.
THE HEARING OFFICER:

23
24
25

So, it's a larger umbrella; but it's still

Anything further on

Item 8?
MR. HOGFOSS:

We'll just note that it is a

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separate requirement in the rules to have a written IMP

2

program that addresses these issues.

3

practice both the Agency and industry refer to O&M

4

manuals and IMP manuals.
THE HEARING OFFICER:

5

And in fact, in

Okay.

Let's --

6

shall we try to hammer out Item 9 before taking a break,

7

or would you-all prefer to take a break?
MS. ATKINS:

8
9

would be short.
THE HEARING OFFICER:

10
11
12

I would like to think it

Okay.

Let's do Item

9 then.
MR. SEELEY:

Okay.

Item 9, again, failure

13

to follow the procedures for creating a Management of

14

Change document.

15

segments for assessment were merged into a single

16

segment, and the appropriate Management of Change

17

documentation was not communicated or executed.

18

we've already talked about the impacts of those mergers

19

in an earlier item, but this item has to do with not

20

creating the Management of Change for the decision to

21

merge the segments.

This relates to when merger of

22

THE HEARING OFFICER:

23

MS. LITTLE:

And

Thank you.

The Company did do a risk

24

analysis in 2005 that talked about what the impact of

25

merging the testable segments would be for the integrity
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management program, ILI assessment; and that analysis

2

concluded that there wasn't any negative impact to the

3

integrity risk assessment process.

4

addition, under the TIARA program, which we've just been

5

talking about, you don't actually -- the dynamic risk

6

assessments, those aren't aggregated.

7

So, they can't be masked over multiple miles.

They can't be.

So, it doesn't matter whether you're one,

8
9

And I guess in

two, four, six or eight segments for purposes of how you

10

are going to be doing the risk assessment process under

11

TIARA.

12

of a testable segment does not impact the risk scores.

13

And that's, I think, from our perspective --

So, you cannot aggregate them.

MS. ATKINS:

14

So, the length

Are you talking -- I'm sorry.

15

Are you talking about the cumulative risk for the

16

testable segment or the identified threats?

17

MS. LITTLE:

18

MS. JONES:

19

22

The individual threats for the

cumulative segment itself.
MS. ATKINS:

20
21

I think that's --

So, weighted average for the

length.
MS. JONES:

For the final segment.

23

goes back to didn't find threats but did not mask

24

regardless of the pipeline segment.

25

MR. SEELEY:

It

I don't know if they're

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through.
THE HEARING OFFICER:

2
3

anything?
MR. WHITE:

4
5

We interrupted -- we

MS. LITTLE:

No.

That's okay.

I think

MS. ATKINS:

Is there a point in here

that's okay.

8
9

Sorry.

interrupted her.

6
7

Do you have

where -- I've reviewed the MOC that's under your brief

10

Tab 10 and brief Tab 11 and 12, and I don't see where it

11

addresses the impacts on the ability to provide the

12

vendor data and ILI reporting within the discovery time

13

frames.
MS. LITTLE:

14

And I think the way that --

15

I'm looking at NOPV Item 9 in the NOPV itself.

16

way in which this is pled, the Agency says, "As a result

17

of the change, the longer testable segments negatively

18

impacted the TIARA risk assessments by masking higher

19

threat intermediate segments (such" -- and then parens,

20

"(such as the Lake Maumelle Watershed and Mayflower

21

populated areas) with the dilution of the risk scores

22

that resulted from the increased length of the testable

23

segment."

24
25

And the

So, again, you know, the Company did in
2005 look at that issue.

And as we said, the dynamic

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risk assessment threats can't be aggregated or masked

2

over the multiple miles.

3

essentially goes away.

So, the testable segment issue

MS. ATKINS:

4

So, as long as an identified

5

threat is identified -- is taken care of, it doesn't

6

matter how long it is?
MS. JONES:

7
8

The identified threat should

be addressed, yes.
MS. ATKINS:

9

So, as we read in that [sic]

10

Section 8 of the TIARA manual, it's important to get

11

those identified threats or else the length aggregates.
MS. JONES:

12

The risk and integrity

13

specialist and the local risk management team and data

14

integration team, they run their individual knowledge of

15

that also in that review.

16

MS. ATKINS:

But to go back to our

17

discussion about combining those segments, was there any

18

consideration?

19

impacts on the vendor's ability to meet the timing

20

deadlines in their vendor specification for providing

21

the reports.

22

address those changes --

23

This goes back to the other item,

Since this is the MOC that was supposed to

MR. KOETTING:

They don't have any trouble

24

running corrosion and caliper tools in the segments in

25

that time frame.
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MS. ATKINS:

1

In the future when they would

2

combine -- when the two testable segments are combined

3

into one, was there an evaluation at that time about the

4

impacts to the vendor?

5

the MOC.

6

to that other --

Because you're saying this is

And that's the question on my part going back

MR. KOETTING:

7

You're saying that

8

combining the segments negatively impacts the business

9

systems.

It does not impact the TIARA --

MS. ATKINS:

10
11

It does not.

This was an informational

question.
MR. KOETTING:

12

Whether it impacted in

13

2005, the running of in-line inspection tool, no, it

14

does not impact the running of inspection tools.

15

capable of running in-line inspection tools 300 miles.

16

It can be done.

17

The length of the line doesn't necessarily impact the

18

ability to get that inspected.
MS. ATKINS:

19
20

Can you have problems with it?

We are

Sure.

Just the data analysis after

the tool's removed from the line is very lengthy.
MR. KOETTING:

21

Depends on what's in the

22

line, what you're looking for.

Depends on how many

23

defects are in the line.

24

hundred-mile line takes longer to assess than a 50-mile

25

line.

You can't say that a

It's just not valid.
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MS. ATKINS:

That's the difference.

2

MR. KOETTING:

It depends on what's in

3

that 50-mile segment.

The length of the line, as long

4

as the tool pusher works it, doesn't affect the ability

5

of the tool to collect data.
MR. WHITE:

6

Let me just point out that

7

that last paragraph -- and I appreciate the focus on

8

what's in the NOPV.

9

paragraph about the impact of the change, you know,

That's only fair.

But the last

10

if -- even if we -- even if we take the argument that

11

there may or may not have been a negative impact, that

12

that sort of goes to the kind of the gravity or the

13

consequences.

14

that the violation or that the penalty amount on the

15

violation should be lower, the consequence of the

16

gravity.

17

And it may be a mitigating explanation

But the -- I don't think that that negates

18

the basis of the allegation, which is the operator

19

failed to follow its own procedures for creating this

20

management of change document.

21
22
23

And, Rod, can you just talk a little bit
about management of change and why it's important?
MR. SEELEY:

I think Molly's more familiar

24

with their processes.

So, if you keep it specific to

25

the Exxon process instead of a generic statement, it
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would probably be better.

2

MS. ATKINS:

I was not provided this 2005

3

MOC.

4

was submitted.

5

this how this MOC anticipated the change in the

6

combination of the testable segments at a later point.

7

So, I hadn't had a chance to look at it until it
But I still was unclear in looking at

So, if it does, I would need some help

8

understanding that.

The MOC process would be to

9

evaluate all of the impacts of the change, and we were

10

concerned that because of the instructions and how we

11

understood the TIARA model, that the increased length

12

and the weighted averages and the weight of the model

13

worked, if we understood correctly which we may not,

14

that there would be -- and what we observed in the

15

calculated scores, that there was some mechanism there

16

that was impacting the ability to identify the risk in

17

the areas in the Maumelle and prioritization of those

18

relative to one another for inspections.

19

So, that risk weighting is important for

20

multiple decisions that are made afterwards.

But the

21

management of change itself should evaluate all the

22

changes implications and have you taken care to address

23

that if we make this change, it will do this and what do

24

we need to do or do we need to do anything to mitigate

25

that, which is in your MOC processes.
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And I'm not sure where your MOC lies, the

1
2

PL2311 that's under your Exhibit 11 is an MOC form

3

number, and I don't know if this falls under your normal

4

procedures.

5

that filters down through your procedures -- and I don't

6

know if it's in the IMP manual, but this resides

7

somewhere in your procedures to complete an MOC for

8

significant change.

I know it's a requirement of OIMS; and if

MR. RANDOLPH:

9

My understanding was the

10

allegation originally was we didn't do an MOC, and

11

you're saying we didn't produce it because, well, we

12

weren't asked.

13

here and now the allegation changes.

14

frustrating that we actually have the document to

15

address it.

16

didn't get a chance to see this until today.

So, we produced the two MOCs and we get

And then now in a hearing, it's, well, I

MS. ATKINS:

17

It's just

I'm sorry, Johnnie, if that's

18

what I inferred.

19

I had a short time to look at it, and I did not see

20

where it addressed the intention to combine the testable

21

segments.

22

so --

25

I'm just saying

And they were not combined until after 2009,

MR. KOETTING:

23
24

I am looking at this.

They were combined 2005 and

2006.
MS. ATKINS:

There's also a bullet that

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says station remained idle and will only use as a status

2

surveillance site for Foreman.
MR. RANDOLPH:

3
4

station, yeah, at that time.
MS. ATKINS:

5
6

At that time.

Is it in use

today?
MR. RANDOLPH:

7
8

That is true for Foreman

If so, we would have

included it in a change before we activated it.
MS. ATKINS:

9

This removal of scraper traps

10

does not discuss combining testable segments.

11

segments are an IMP plan, not a physical structure.

12

I guess I could not read into here or obtain from this

13

information where the implications of combining the

14

testable segments, which have a lot of things to do in

15

your risk model and your assessments, where this was

16

addressed.
MS. MCDANIEL:

17

Testable

Or that might have been a

18

change that addresses the change from four testable

19

segments to two testable segments.
MS. ATKINS:

20

So,

That's the part that I don't

21

find in here.

And so, all I'm saying, if it's in here,

22

I don't see it; but I've only had a short time to

23

review.

24

shows the evaluation of the combination of the testable

25

segments --

If you can provide me an explanation of what

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MR. WHITE:

1

Yeah.

Maybe there's some

2

additional records that can be provided in this hearing

3

on that issue, and that would clear it up.
MS. MCDANIEL:

4

I think that addresses your

5

question, that the allegation is that there was not an

6

MOC for the merging of the testable segments.

7

that's what I think we're saying, is what we see here

8

doesn't seem to respond to that for that -- I mean, yes,

9

it was a management change form; but it's not our

And

10

allegation from four testable to two testable segments,

11

that that was created for that purpose.
THE HEARING OFFICER:

12

Okay.

Okay.

Anything

13

further on Item 9?

I suggest we take a 10-,

14

15-minute break and resume with four Items 1 through 4.

15

We're off the record.

16

(Recess from 10:01 a.m. to 10:17 a.m.)

17

THE HEARING OFFICER:

We'll go back on the

18

record.

19

Did anyone have anything to add before we move to Item

20

1?

21

And we just finished with Items 5 through 9.

MS. LITTLE:

Yes.

We wanted to just

22

revisit one thing for clarification purposes with

23

respect to TIARA, and this relates to NOPV Items from

24

back towards our discussion for 8 and 7.

25

THE HEARING OFFICER:

Okay.

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MS. LITTLE:

1

Just to clarify for

2

everybody's benefit, the purpose of TIARA -- which is

3

meant to be a five-year forward look.

4

yes, we're going to do an ILI assessment, it means that

5

the ILI's going to be done somewhere in the next

6

five-year period.

7

wanted to make sure that was clear in terms of what the

8

purpose of TIARA is.

9

inputs, it's considering them for the next five-year

So, when you say,

That's how it's designed.

So, we

So, when you're putting in the

10

period, irrespective of when it is you're doing it

11

within that five-year period.
And then the other point of clarification

12
13

we wish to make is that when you're running a

14

sensitivity analysis, you're not manipulating the

15

process.

16

cross-check of the process.

17

that that was clear as well.

You're simply -- it's almost like a
And we wanted to make sure

THE HEARING OFFICER:

18

Okay.

Thank you.

19

So, Items 1 through 4, we're going to do those

20

individually, right, and in order?
MR. WHITE:

21
22

25

Rod, do you want to

start with that?
THE HEARING OFFICER:

23
24

Yeah.

Okay.

Item 1,

please.
MR. SEELEY:

Okay.

Item 1 of the notice

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alleges that the operator didn't include all relevant or

2

pertinent information in determining the -- in

3

performing their assessment schedule which relates to --

4

specifically, the operator did not include information

5

regarding material and other test data that they had to

6

create their assessment schedule or get the assessments

7

for the Pegasus Pipeline, things that were not concluded

8

from our analysis [sic] or review, manufacturing

9

information, toughness, again hydrostatic testing

10

history, all related to the low frequency ERW pipe in

11

their system.

12

THE HEARING OFFICER:

13

MR. HOGFOSS:

14

THE HEARING OFFICER:

15

MR. HOGFOSS:

Thank you.

You want us to go ahead?
Yes.

I guess kind of a threshold,

16

Items 1 through 4 are clearly related; and it's

17

primarily the issue on Item 1.

18

have the most discussion there.

19

really kind of a footnote to Item 1 in series.

20

Okay.

So, I expect we will
And then 2, 3, 4 are

But to begin with and just to kind of

21

preface our discussion on those four items, you know,

22

the way we read the NOPV and the related materials, the

23

violation report, is that clearly it presumes that

24

simply because the incident occurred, there must be a

25

violation of Part 195 regs; and that's not the way that
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the Pipeline Safety Act or the regs are written.
The regulations establish minimal

2
3

standards that industry must meet, and the intent is and

4

the hope by both Agency and industry is that that will

5

detect and prevent incidents.

6

we've said in our written materials, we think the Agency

7

should take credit for the fact that certainly the IMP

8

rules over the last 12 years have had a positive effect.

And, in fact, something

If you look at the data, a couple of

9
10

notable achievements, that certainly the -- 12 years ago

11

the leading cause of pipeline incidence was third-party

12

strikes.

13

has plummeted largely as a result of the "call before

14

you dig" regulations and the efforts made by both

15

industry and agency with 811.

That's -- the incidence of third-party strikes

16

Then the leading cause of incidents became

17

corrosion and really helped force [sic] that technology,

18

the development of corrosion and in-line inspection

19

tools that would better detect corrosion.

20

rules as we were discussing earlier established

21

timelines, criteria for repair; and that's had an

22

effect.

23

of those types of incidents.

And the IMP

There's been a decrease both in number and size

24

The leading cause of pipeline incidents on

25

liquid pipelines now is material defects, which is where
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we are with this issue.

2

has to do with pre-70 low frequency electric resistance

3

weld or ERW pipe.

4

be talking about this a fair bit.

5

that the Agency recognizes, industry recognizes, the

6

scientific community recognizes is in finding all of

7

those defects.

And the difficulty -- I'm sure we'll
But the difficulty

But the starting point for us is that

8
9

The issue for Items 1 through 4

simply because an incident occurs does not necessarily

10

mean that there's a violation of the regulations.

It

11

may in many cases or in most cases, and that's something

12

that we'd be curious to hear the Agency's response on.

13

But the law simply isn't written that way.

14

have been -- strict liability is the concept where there

15

is liability without fault.

It could

And the Clean Water Act has that specific

16
17

to oil pipelines.

18

waters, you are liable for a penalty regardless of how

19

it happened.

20

Congress didn't say that for the Pipeline Safety Act.

21

So, that's an important starting point.

22

It says if you spill oil in U.S.

We don't care what the cause was.

Again, we all wish this incident wouldn't

23

have happened; and we'll come back to that, too, is that

24

we scratch our heads as to how anything alleged as

25

violations in here alleged that the Company failed to do
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something that would, in fact, have found this anomaly

2

in time to prevent it.

3

and we will eventually come back and certainly want

4

Cliff's input from his years of NTSB as to what can be

5

done, what's the state of the art right now; and that's

6

important.

And that's an important concern,

There's a lot of things as the Region

7
8

certainly knows and refers to in some of the materials

9

that have been done even since this incident occurred.

10

And we'll want to talk about that.
MR. SEELEY:

11
12

Before you go on, can I ask

one question?

13

MR. HOGFOSS:

14

MR. SEELEY:

Yes.
You made a statement that you

15

presume that this item is in here solely because of an

16

accident that occurred.

17

where you draw that conclusion?

Can you point in the notice

MR. HOGFOSS:

18

I think the entire -- I

19

think all of the -- the fact of the enforcement itself,

20

we wouldn't be here at this table today if there wasn't

21

an incident.
MR. SEELEY:

22
23

verbiage in the notice that says that?
MR. KOETTING:

24
25

Is there particular verbage

sentence.

Probably the first

March 29th it says pipeline ruptured.
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MR. SEELEY:

1
2

That's just the fact of an

event.

3

MR. KOETTING:

4

MR. SEELEY:

5

MR. WHITE:

It gave rise to the

investigation.
MR. HOGFOSS:

8
9

It's not the basis of the

notice.

6
7

Yeah.

Yeah.

Actually in the

Pipeline Safety Violation Report, too, it says that the

10

Company failed to do all of these things, you know.

11

And, yet, it doesn't say they would have prevented an

12

accident.

13

wasn't an incident, we wouldn't be here.

But clearly -- I mean, the point is if there

Perhaps a more direct response would be,

14
15

that the Agency had inspected this Company, this

16

specific pipeline, did have a very thorough audit in

17

2007 of these exact processes, IMP and TIARA and OIMS,

18

long before this incident occurred and found no fault

19

with the processes then.

20

mistake in the process.
MR. WHITE:

21

So, there was no glaring

I think one thing that Rod's

22

trying to get across, though, is you're right.

It's not

23

a strict liability; but I think it's incorrect to say

24

that just because there was an accident, there's always

25

an NOPV.

I mean, there are times when accidents happen;
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and the investigation determines that it was because

2

of -- there was a third-party strike the month before or

3

something and there was no probable violation.

4

the case that just because a spill happens, we

5

automatically generate an enforcement.

6

case, just to be clear about that.
MR. HOGFOSS:

7

It's not

That is not the

Well, again, though, I will

8

say that the Region has inspected the Company's programs

9

and processes and specifically this pipeline and did

10

find no glaring error.

And now after the incident, you

11

know, there's a lot of alleged violations that we think

12

are not proper.
But it does get to the point of really

13
14

what do regulations require, and the regulations

15

clearly, especially integrity management, but all of

16

Part 195 are process-oriented.

17

each operator establishes a process and a set of written

18

procedures.

19

of law.

20

after there is any type of incident.

21

following the rules and your procedures, that's a

22

violation.

23

case.

24
25

They say establish --

And your written procedures have the force

We'll inspect them.

We'll review them again

We understand that.

And if you're not

But we disagree in this

And I guess we should move into Item 1.
I've been trying to postpone it, Rod.
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MR. SEELEY:

That's all right.

2

MR. HOGFOSS:

But here's the -- again, the

3

legal issues presented as specific nine alleged

4

violations, it really goes to processes.

5

included in our written materials -- and this is clear

6

in the IMP regs -- the Agency requires and industry

7

responds that it's a continual process.

8

It's a loop where you are constantly doing inspections.

But as we

It never ends.

And the point here is at a very broad

9
10

level on Item 1 is that this isn't a case where you have

11

an operator that just really failed to be looking at its

12

assets.

13

occurred, the Company had done three hydro tests.

14

had done three in-line inspections, one of which was

15

with a seam/crack tool.

16

failure analyses or engineering analyses.

17

clearly looking at this issue.

18

In this particular pipeline where this incident
It

And it did four susceptibility
So, it was

And in the process of that, which really

19

went on over a couple of decades, think of the dozens

20

and dozens of engineers and managers reviewing all of

21

these issues, reviewing the rules and the procedures,

22

the engineers within the Company, the engineers at the

23

tool vendors looking and grading the results.

24

metallurgists looking when there are hydro test breaks

25

and giving their third-party reports, certainly

The

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post-incident, the -- all of the various experts looking

2

at things.

3

And most importantly, when it comes to

4

experts, someone that the Region notes in the supporting

5

materials to the NOPV, being primarily the Pipeline

6

Safety Violation report, there's an accurate history

7

that chronicles how government, industry and the

8

academic community has looked at this ERW pipe issue

9

since the 1980s.

10

And from the very beginning who the

11

industry has trusted and relied on this to as recently

12

as January 2014 is the metallurgist John Kiefner who is

13

getting older now but is really the leading authority

14

who has been cited by the Agency, who has been hired by

15

the Agency, just published a report in January of this

16

year on this very issue.

17

And significantly, the Agency retained

18

John Kiefner and Michael Baker in 2004 to prepare an

19

analysis on this very issue, to ask them, to say please

20

help us analyze what are the best tools to look for ERW

21

defects, what are the best processes that we can

22

consider to require or recommend as guidance for

23

industry to look for ERW defects.

24

report came out, and it provided a proposed methodology

25

to do just that.

And the Baker/Kiefner

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The Agency recommended it as guidance, did

1
2

not change any rules.

Actual rules in Part 195 that

3

address the ERW are quite minimal.

4

if you find that there's a threat to when you go through

5

your IMP process to identify threats, then you need to

6

do -- you need to look at P&M, preventative and

7

mitigative measures or you need to do an engineering

8

analysis to look at it.

They say if you --

So, what this company did -- and it's in

9
10

the record -- they actually hired John Kiefner -- we're

11

not talking post-incident.

12

IMP rules first came into effect -- to actually help the

13

Company work through the report that the Agency

14

commissioned, the Baker/Kiefner report, and apply it to

15

their processes.

16

come up with a software program to implement which the

17

Company uses today, which many companies use today.

We're talking about when the

And John Kiefner helped this company

You fast forward that a ways and Kiefner

18
19

and another national expert named Kent Muhlbauer, who's

20

really one of the leading authorities on pipeline risk

21

management, also worked with the Company early on in

22

their integrity management planning process and had

23

input.

24

Company asked them to look again and say help us

25

understand how this happened, how we can avoid this in

Both of those experts now after the fact, the

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the future, how we can improve our methods, our tool

2

selection.
And you'll see as Exhibit 1 in our

3
4

materials, the affidavit from John Kiefner that says

5

very clearly -- and let me actually turn to -- I believe

6

it's in Exhibit 1, Paragraph 23 and 24.

7

is saying that he's discussed these ERW detection issues

8

with the OPS, with the Agency recently.

9

Agency's aware that there's not one tool that can be

23 John Kiefner

And the

10

expected to identify all ERW anomalies all of the time.

11

What he's referring to there is, in fact,

12

the most recent report.

We'll come back to it and how

13

that report came about, what we're referring to as the

14

Battelle report.

15

that, you know what, we're not there.

16

with technology yet.

17

procedures yet.

18

concluded by saying it is urgent that both PHMSA and

19

industry work to force technology, work on this further.

20

We find that in stark contrast to the NOPV

But that concluded as well is [sic]
We're not there

We're not there with management

And in fact, the Battelle report

21

which accuses this company -- and it says it quite

22

clearly in the violation report -- that the Company had

23

more than adequate information to be able to find this

24

defect.

25

Agency's done, including post-incident Battelle report.

That flies in the face of everything the

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Most importantly, it flies in the face of what John

2

Kiefner himself says here.
If you look to Paragraph 24 in his

3
4

affidavit, he says he has reviewed the data.

He

5

reviewed the metallurgy reports for the root cause

6

failure analysis submittal.

7

saying that based on his considerable experience, it's

8

his opinion that "the pipe at the point of failure was

9

unique, that [sic] the anomaly that caused the incident

And he ends at Paragraph 24

10

was not capable of reliable detection given that it

11

exhibited atypical characteristics not frequently seen

12

before in the industry."
You really can't find a more relevant

13
14

expert to opine on this.

15

issue for decades for the Agency, for the industry.

16

to us, that really is the entry point to us discussing

17

Item 1.

18

failing to consider all of the required information in

19

order to identify the risk of seam failure on ERW pipe,

20

our response is we did.

21

He's been working on this
And

If the Company's criticized for failing --

We did consider it.

We're being faulted because we didn't

22

conclude that there was a risk and, yet, the Company

23

proceeded as if there was.

24

we think this one's fine.

25

done hydro tests.

They didn't simply say, no,
Forget about it.

They've done ILI.

They've

They've done

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2

engineering analyses.
So, that's the entry point.

I don't know

3

if anyone else on this side wants to add something.

4

should let Rod and company respond at this point.

5

sure we have more to talk about.

6
7
8
9
10
11

MS. LITTLE:

We
I'm

I don't know if you want to

go to the specific points yet or just wait.
MR. HOGFOSS:
open the floor on this one?

It's up to you.

Shall we

Or do you have anything

more to say as kind of an opening?
MS. LITTLE:

Well, I think just to harken

12

it to -- and I think that is the background that's

13

appropriate for discussing Item 1.

14

itself is that the Company didn't -- did not -- we think

15

that the allegation essentially is saying that the

16

Company didn't conclude that the pipeline was

17

susceptible to seam failure, and that is the issue that

18

the Agency has with the Company.

19

The allegation

And as Bob said, the IMP does not require

20

an operator to conclude a risk exists.

It requires you

21

to consider that there are all these different risks.

22

And you may conclude based on what your various end

23

points of -- input of information, your data points are,

24

that it exists.

25

It doesn't force a conclusion.

But it doesn't require a conclusion.
It forces consideration.

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And Part 195.452 says you have to consider

1
2

all nine applicable threats, including manufacturing

3

history, including prior integrity assessment result and

4

you need to document that process.

5

established both in the brief and the exhibits that the

6

Company did just that.

7

factors, including seam susceptibility, multiple times

8

based on all the available information.

And we think we've

They evaluated all the risk

9

And when the Company first prepared its

10

IMP program, the BAP, the Company incorporated a long

11

seam failure susceptibility process based on the Baker

12

report and with input from John Kiefner himself at that

13

time.

14

their exhibits -- I mean both of their affidavits --

15

talk about that process, the preparation of the program

16

and the status of the Company's program today as being

17

robust.

And I think both Kiefner and Muhlbauer in both of

Kiefner, as Bob mentioned, created the

18
19

Pipelife [sic] for -- at the request of the Company and

20

then later made that available to the industry to help

21

analyze the pressure cycling and used fatigue data as

22

part of the long seam susceptibility failure analysis.

23

And the Company both -- and I think Bob detailed the

24

years.

25

all the different years in which the seam susceptibility

We have an exhibit, I believe, that goes through

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failure analysis was conducted, 2004 and 2005, again in

2

2007, again in 2009, and again in 2011.
And every time using the process that was

3
4

developed with Kiefner himself, the Company concluded it

5

wasn't susceptible to longitudinal seam failure.

6

making those determinations, the Company looked at all

7

the pieces of information that the Agency expects the

8

Company would look at:

9

leak history; prior pressure testing; third-party

And in

Pipe manufacturing information;

10

metallurgical analysis of the 2005, 2006 seam failure;

11

using the PHMSA-endorsed Baker and Kiefner process;

12

consultation with Kiefner himself; and let's not dismiss

13

over 60 years of operating history and maintenance

14

history.

15

Kiefner himself says, I think it's in

16

Paragraph 13 of his affidavit, that -- 19?

17

"Hydrostatic test failure alone is not an indication

18

that a pipe is susceptible to seam failure."

19

to be evidence of fatigue-related failures, selective

20

seam corrosion or other time-dependent defects.

21

13.

There has

So, what Kiefner then says is, If -- and I

22

think this is also in the Baker report, 2004 -- if ERW

23

pipe -- no threat exists if ERW pipe is successfully

24

hydro tested, operated in a manner that stress [sic]

25

levels and pressure cycling prevent [sic] it from being
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susceptible to fatigue and adequate coating and CP

2

exists to prevent selective seam corrosion.
So, the Company applied its long seam

3
4

failure susceptiblity analysis to Pegasus, factored in

5

all those results into its threat identification and

6

risk assessment analysis and concluded time and time

7

again that this particular line was not susceptible to

8

seam failure.
Do you want to add more?

9

MR. HOGFOSS:

10

What the ultimate irony is

11

that the Company did use a seam/crack tool, we believe

12

not required to do so but they did on this line, and it

13

did not find this anomaly.

14

speaking to saying -- and they used multiple tools at

15

this point.

16

not a tool out there.

That's what John Kiefner is

And John Kiefner said, you know, there is

17

Now the Pipeline Safety Violation Report

18

goes so far, which is beyond the statement of the law,

19

to say that the Company should have used a different

20

tool, should have known that a TFI tool would not find

21

this.

22

EMAT tool.

23

experts -- the dozens of engineers and the very experts

24

retained and commission by the Agency clearly say there

25

is no one tool that can find ERW all of the time.

And says you should have used the UT tool or an
Well, the law doesn't say that; and the

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They recommend doing hydro tests.

1

The

2

Company did that on this line.

They recommend doing

3

multiple tools.

4

that is the ultimate irony here.

5

us, only because this incident occurred.

6

ultimate irony is had the Company done everything that

7

it's alleged to not have done, it still would not have

8

found this particular defect.

The Company did that on this line.

So,

We are here, all of
And the

That doesn't mean the ERW defects are not

9
10

found often.

They are.

And the technology is

11

improving, and the methodology and the industry and the

12

Agency's ability to sift through all of the data and

13

find these highly unusual defects is improving.

14

there's nothing that would have found it in this case

15

short of perhaps a hydro test done in the last couple of

16

days.

17

fracture that happened in a matter of days.

But

It appears that this was a very rapid growth

So, a tool run, multiple tool runs a month

18
19

before, a year before, well, didn't find it.

And, you

20

know, again, that's the backdrop in which we're talking

21

about this.

22

how can we get -- it would be nice if we would look to

23

the allegations in the NOPV and say, yes, but for that

24

alleged violation, we would have caught this one.

25

that's not the case, and that's very important for the

And I know that we do all share the goal of

But

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entire backdrop to this matter.
MS. LITTLE:

2

And I think the last point we

3

can make, too, is just looking, again, at Kiefner.

And

4

we mentioned before PHMSA has obviously inspected the

5

Company numerous times but in particular did an in-depth

6

inspection in 2004 -- I mean, 2007, excuse me, of the

7

Pegasus Pipeline of the long seam failure susceptibility

8

analyses that have been done of the Company's process

9

for how it is they conduct that engineering analysis,

10

and there weren't any issues raised.

And not

11

surprisingly, Kiefner didn't raise any issues either.

12

In his affidavit in Paragraph 19, he's

13

very clear, "I have reviewed the integrity data that

14

would have been available to EMPCo prior to the incident

15

regarding the Conway to Corsicana testable segment.

16

Based upon that review, EMPCo's conclusion that the

17

segment was not seam failure susceptible under federal

18

regulations was reasonable and was consistent with the

19

seam failure susceptibility determination guidance

20

available prior to March 29th, 2013."
Nevertheless, the Company conducted --

21
22

EMPCo conducted the hydrostatic test on the Conway to

23

Corsicana segment in 2006 and a seam integrity

24

assessment in 2012 utilizing an ILI crack detection

25

tool.

Neither of these activities, unfortunately,
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revealed the presence of the defect that was the origin

2

of the March 29, 2013 failure.
Even Kiefner has reviewed and knows what

3
4

the Company has done here to determine whether or not

5

this line is seam susceptibility, is susceptible to seam

6

failure.

7

that's at this point fairly well-accepted on these very

8

issues with respect to this very type of pipe.

9

obviously we find that compelling, and the Company

And Kiefner is the leading expert.

I think

And

10

believes that it's done this process just as it should

11

have done this process.

12

MR. HOGFOSS:

13

THE HEARING OFFICER:

14

Open it up for discussion?
Thank you.

Anything

in response?
MR. SEELEY:

15

We can start a little bit of

16

discussion.

I want to go back to that the -- we sort of

17

get to the conclusion, but the allegation is actually to

18

the methods and processes that get us to the conclusion,

19

not the actual conclusion itself.

20

conclusion because that's what happens when you run

21

through a process.

But we end up at the

You referred to many times Kiefner's

22
23

affidavit.

And since he's not here, I guess I'm going

24

to ask you-all about it, since he's not here for me to

25

ask him.

One thing, you also referred to the Baker
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study in which Kiefner & Associates was a coauthor, if

2

you will, or a participant in that study.

3

The one question I have is a seemingly

4

inconsistent statement between his affidavit and the

5

study itself or Item 13 you brought up that says

6

hydrostatic test failure alone is not an indication that

7

a pipeline is susceptible to seam failure.

8

13 from his affidavit.
THE HEARING OFFICER:

9
10

That's Item

You mean Paragraph

13?
MR. SEELEY:

11

Yeah, Paragraph 13, of his

12

affidavit.

13

Section 4.3.2 starts off with, "If seam-related in

14

service or hydrostatic test failure has occurred on the

15

segment, the segment is considered susceptible."

16

I'm wondering, could you help me understand the

17

seemingly conflicted statement between the two?
MR. HOGFOSS:

18
19

Kiefner's not here.

22

So,

Well, first to comment that

He's semi-retired.

MR. SEELEY:

20
21

And then if you turn to the Baker study,

I can't ask him.

So, I have

to ask you.
MR. HOGFOSS:

He doesn't need to be here.

23

His statements are quite clear and unequivocal and

24

they're not isolated.

25

Baker in a second.

We'll get to your comment about

But they're consistent.

They've

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been consistent as cited in the violation report for the

2

last 15, 20 years on this issue.
MS. LITTLE:

3

And actually I think they are

4

consistent.

The point that is made in the Baker report

5

is if a seam related either in service or hydrostatic

6

test failure has occurred, what Kiefner is saying is

7

hydrostatic test failure alone isn't an indication and

8

he talks about the different reasons.

9

about the different reasons and you want to investigate

And he talks

10

them for fatigue or selective seam weld corrosion or

11

other time-dependent phenomena.
And what he's saying is if it's neither

12
13

fatigue-related crack or more selective seam weld

14

corrosion, nor evidence of another form, it's reasonable

15

to certify that they're not an indication that the

16

pipeline is susceptible.
MR. SEELEY:

17

So, he seems to jump to

18

the -- to the point that his analysis is related to or

19

his conclusion is seemingly related to pipe of a ductile

20

nature that will fatigue over time and not specifically

21

dealing with pipe of a brittle nature that would not

22

experience that same fatigue growth.

23

have evidence that your pipe and other sections of this

24

pipeline exhibit more of a brittle nature than a ductile

25

nature.

But, in fact, we

So, the applicability of his statement or
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analysis would be flawed in that ductile pipe does not

2

act like brittle pipe.

3

that?

Would you agree or disagree with

MR. KOETTING:

4

It does not.

You are

5

correct.

A brittle piece of pipe with a defect in it

6

will fail at lower hydrostatic test pressure than a more

7

ductile piece of pipe.

You are correct.

8

MR. RANDOLPH:

Can I just --

9

MR. KOETTING:

What is counterintuitive,

10

though, is when you look at brittle pipe failure and

11

aggressiveness versus ductile pipe failure, almost every

12

time ductile pipe has a shorter reassessment interval

13

than brittle pipe, almost every time.

14

survives is so much larger.
MR. SEELEY:

15

The defect that

But you're also jumping to

16

the conclusion and not the process of identifying this

17

pipeline as susceptible.

18

have longer time to assess it situation instead of do I

19

even need to address that risk factor.

20

over it again.

21

identifying as we need to be considering this line

22

susceptible.

23

So, you've jumped to the, I

You just jumped

I'm trying to stay into the process of

MR. RANDOLPH:

I just want to clarify the

24

original question about the Baker report and whether it

25

was inconsistent.

You have to read further down in the

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Baker report at Page 26 where he says, "Failures that

2

occur during the hydrostatic test should be investigated

3

for evidence of fatigue."

4

no fatigue-related failures exist, it is reasonable to

5

certify that the pipeline is not susceptible to seam

6

failures in the context of the Federal Integrity

7

Management requirements."

8

the Baker report.
MR. HOGFOSS:

9
10

He then later continues, "If

That's a direct quote from

But I don't think he

considers that -MS. ATKINS:

11

Further in the Baker report,

12

he also premises that on if this test is sufficiently

13

high enough.

14

And so, sufficiently high enough is -MR. SEELEY:

It gets back to the previous

15

testing parameters and whatnot.

16

on the fatigue and the ductility.

17

talks about things to consider, which goes back to the

18

allegation of items that need to be considered is the --

19

for example, the toughness of the pipe.

20

specifically applying the toughness values of this

21

pipeline would not lead you to the ductile pipe, which

22

would be related to -- it creates a brittle pipe

23

situation which creates a different scenario that you

24

have to evaluate.

25

MS. ATKINS:

Also, it solely relies
In the report it

And

But it's brittle in the area

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of the ERW seam.

We aren't saying the body of the pipe,

2

but the seam itself is exhibiting those brittle -- [sic]
MR. SEELEY:

3

So, you can't keep continuing

4

to do the ductile fatigue analysis because you know at

5

some point it's not that type of characteristic.

6

didn't see that being considered in your analysis as

7

well.

We

8

So, I guess I'd like to ask, you know:

9

How did you-all incorporate that particular piece of

10

information into your analysis process that it wasn't

11

ductile?

12

fatigue phenomenon as you maybe experienced in other

13

areas.

It was brittle?

We have to consider that and address that.
MR. HOGFOSS:

14

It won't experience the same

Engineers clarify this, but

15

your point is well taken but for the fact that it's not

16

as though the Company said, oh, this is not seam

17

susceptible; so, we won't consider it further.

18

did.

19

engineering assessments, and they included and

20

considered all of these factors.

21

that are considered.

22

They did hydro test.

MR. SEELEY:

They did ILI.

They

They did

Those are the factors

The question of the hydro

23

test is not simply saying, I did a hydro test.

There

24

are types and methodologies within a hydro test that go

25

to address a particular risk.

In our evaluation of the

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records, the hydro tests that we see do not seem to be

2

demonstrating that the operator was addressing that

3

particular threat.

4

normal hydrostatic test does not necessarily evaluate

5

particular seam flaws that this would require.

6

They did a strength test, not -- a

And in the literature you will find that

7

they would recommend the hydrostatic test at a higher

8

pressure level, stress level within the system.

9

were not conducted.

10

MR. HOGFOSS:

Those

A couple of questions.

So,

11

what does the IMP rules say, and further O&M rules, in

12

terms of hydrostatic test pressure for ERW pipe?

13

do the rules say?

14

MR. WHITE:

I can answer that.

What

Actually

15

if you look at the pressure testing code, which is in

16

Part 195 and you go to 195.303(d), it actually does

17

address ERW pipe.

18

from an opinion by anyone's expert.

19

letter of the code.

20

pre-1970 ERW pipe and lapwelded pipe is deemed

21

susceptible to longitudinal seam failures unless an

22

engineering analysis shows otherwise."

And I'll quote it.

And this is not

This is the black

195.303(d), and I'll quote, "All

23

So, I think to Rod's point --

24

MR. HOGFOSS:

25

hydrostatic test pressure.

But was asking about
But we'll come back to that.

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I'm glad you brought that up.
MS. ATKINS:

2

As an assessment method, if

3

that's what you're asking, Subpart E hydro test is an

4

assessment method.
MR. WHITE:

5

I want to make the point that

6

the presumption -- we've talked about ERW pipe.

7

just to step back for a minute, I mean, the reason why

8

that's in the code and has -- and the reason -- ERW

9

pipe, there is extensive metallurgy that has been done

10

with failures related to that.

11

I think everyone's acknowledging that there were

12

hydrostatic test failures.

And

And the fact that -- and

And the integrity management regulations

13
14

require an operator to consider all available and

15

relevant information.

16

where ER -- where we know we have ERW pipe, the code

17

sets up a presumption that the pipe is susceptible --

18

and this doesn't even say there had to have been

19

failures.

20

hydro test failures and then you look at the nature of

21

the hydro testing that was done, you know -- so, you

22

know, Bob, you talked a lot about the issue that this

23

particular flaw failed at the Mayflower site possibly

24

couldn't have been found even if a different type of

25

tool had been used because of the state of the

And so, if we had a situation

And then you add on top of that there were

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technology.
But, again, the allegation is not that the

2
3

operator did not find that particular anomaly.

4

allegation is that in its procedure, in its overall

5

process of implementing the risk model, that this risk

6

factor should have been accounted for in a way that it

7

wasn't.

So, I just wanted to clarify that.
MR. SEELEY:

8
9

The

To answer your question,

literature and the documentation in the analysis would

10

show that a hydrostatic test within the pressure ranges

11

from 90 to 100 percent SMYS would be the test that is

12

considered one that would assess for the seam risks or

13

threats.

14

the line was not subjected to that particular type of

15

test.

The test records that we reviewed showed that

MR. HOGFOSS:

16

And the point I was getting

17

at was that the Agency has not promulgated a rule, and

18

we're talking about violations -- alleged violations of

19

rules, of the law.

20

rule that tells you what test pressure to test ERW pipe.

21

Also, 303(d), I don't have it open in front of me, but I

22

believe it says risk-based alternative, right?

23

promulgated in 1998.

24

operators that wanted to elect a risk-based

25

alternative --

The Agency has not promulgated a

It was

It was a one-time opportunity for

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MS. LITTLE:

2

MR. HOGFOSS:

As opposed to testing.
-- to testing.

The Company

3

did not elect that.

That's totally irrelevant.

I

4

understand what it says.

5

It's not even alleged as a violation in the NOPV.

6

really the only benefit it has for the Region's position

7

is it says in that case if you raise your hand, you will

8

deem for purposes of being allowed to use a risk-based

9

alternative -- this is pre-IMP, remember.

We understand what it means.
And

It was kind

10

of the evolution of IMP -- you will be allowed to do

11

that if you deem it seam susceptible.
But then we fast forward to -- and I

12
13

understand.

Rod's absolutely right.

What the current

14

state of the science seems to be is that when we look

15

for these -- and, yes, brittle pipe is a concern.

16

do we find it?

17

defects, one of the things that came up, again,

18

post-incident?

How

How do we find these hard-to-find

So, right now the state of the agencies --

19
20

and the Agency hasn't even endorsed it.

It simply paid,

21

commissioned, Battelle and DNV, Det Norske Veritas, and

22

John Kiefner to look at these issues.

23

with a still work-in-progress report October 27th last

24

year.

25

specific to this issue, came out in January of this

They came out

John Kiefner's Report Number 3 within that, very

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year.
And they do say in there, they say --

2
3

well, they say a couple of things.

They say this is a

4

tough issue.

5

identify actions that operators could implement.

6

don't have a silver bullet here.

7

that we're getting better.

8

the same way it was for corrosion.

9

ends with saying, two quotes from the end of the

We don't have the answer.

NTSB told us to
We

What we do know is

The technology can be forced
And it says -- it

10

Battelle report from October 27th.

There should be an

11

urgent effort by PHMSA and the industry to develop an

12

enhanced technology that will identify ERW defects.
The next paragraph they say, It is clear

13
14

that gaps remain, both in understanding the ERW failure

15

process and in quantifying the effectiveness of current

16

methods to manage ERW.

17

post-incident.

18

Rod was stating, that say, you know, run higher test

19

pressures.

20

That's the ultimate irony, is that, yes, the Company

21

concluded using the Agency's recommended guidance

22

because it was not in the rules to follow the Baker

23

report.

24
25

That's state of the art.

That's

And in that report, they do say -- as

Well, that's what this company is now doing.

The Company did that.
Consultation with John Kiefner

concluded -- John Kiefner says now after the incident
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that it was proper to conclude that it was not seam

2

susceptible; and, yet, they still did more than what was

3

required by the IMP rules.

4

They ran a crack tool.

5

that the violation report critiques them and says, Well,

6

you ran the wrong tool.

7

guidance does it say what tool to run?

8

tool capable of detecting cracks.

They continued to assess.

And that's the irony, I find, is

Where in the regs or in the
It says use a

So, I mean, these are part of the problems

9
10

we have with the allegation the way it's made.

11

hindsight is perfect, but you have to go back to what

12

are the elements of their claim.

13

violation here?

14

impression in our pre-hearing brief as well.

15

we be doing what the recently 4.2-million-dollar

16

Battelle-commissioned report recommends, is that both

17

the Agency and the industry keep working on this,

18

instead of doing Monday morning quarter-backing and

19

slamming a company for failing to do things that they

20

actually did?

23

What's a real

And shouldn't we -- and this was our
Shouldn't

And with that, I'll let the engineers talk

21
22

And

more.

Sorry.
MS. ATKINS:

I have to accept that there

24

are some things that that Battelle report says,

25

particularly that the Pipelife model and similar
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log-secant models are not appropriate for the materials.

2

And if you go back to the Baker 2004 report, the purpose

3

of that report on Page 6 of the Baker report was to

4

evaluate the acceptability of using ILI technology to

5

evaluate the integrity of low frequency ERW pipe seams

6

in lieu of a hydrostatic test as currently required.

7

The conclusion of the report was very

8

specific as to whether or not it was brittle or low

9

toughness materials well below 25, which all of your

10

materials are in the three to four range from the

11

hydrostatic test and the failure site and would have

12

concluded that this needed to be hydrostatically tested

13

due to the low toughness and would have had superior

14

results to the ILI.
We've not alleged that as a violation.

15
16

What we have alleged is that the results of the previous

17

integrity assessment, defect type and size that the

18

assessment method can defect and the defect growth rate,

19

you've demonstrated and repeatedly stated that there has

20

been no fatigue observed in any of the 11 seam failures

21

or this one.

22

growth model or the assessment without looking at

23

toughness, without looking at the rest of the Baker

24

report.

25

Yet, you continued to use fatigue crack

And so, it appears that there were
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portions of the Baker report that were incorporated into

2

the processes but not the rest.

3

Kiefner's statement is interesting, and not just the

4

things that he says but the things he doesn't say.

5

says that EMPCo followed the flowchart, but he didn't

6

identify which one.

7

flowcharts.

8

exhibits, there's Figure 1.

9

that that has evolved over time and it has updated to

For example, I think

He

Because the Baker report has two

And Section 4 that you included in your
That report clearly states

10

Section 9.

There's a process in Section 9 that was

11

available in 2004 at the time of the report that has a

12

slightly different process and requires an engineering

13

analysis.
This is not part of your IMP procedures

14
15

that I could find.

So, the Section 9 of the Baker

16

report that took Kiefner's work, which he was an author

17

to, updated it and said that these are additional

18

learnings and additional practices that we recommend.

19

So, when I look at your continuous process, learning and

20

use of all available information, it appears that there

21

are pieces that are used but not all of it.
And in his statement that you are using,

22
23

the flowchart, by not saying which one, it's clear to me

24

that there are statements in here that are maybe

25

missing.

What's the relevance of the hardness that he
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mentions?

Hardness is not a factor in the Pipelife

2

model or the fatigue crack growth.

3

toughness.

4

of the modeling and the use of pipeline and the

5

commonality among the 2005, 2006 hydro test failures and

6

the metallurgical reports.

7

similarities clearly point out a brittle ERW seam that

8

does not appear to be considered in any of these

9

processes.

He doesn't mention

Toughness is a very critical factor in all

And those determinations and

The size of the defects that were observed

10
11

in the failures appear to be below the threshold of

12

detection for a TFI tool -- a TFI tool has to have a .1

13

millimeter air gap for the crack opening.

14

has zero millimeter stated, as you provided information

15

to us that the tools you want to use in the future.

16

While that still is not a guarantee, we agree that --

17

with you that there are things we need to learn.

A UT or EMAT

But not learning from the information that

18
19

we do have and applying it in the processes and the

20

selections of the risk assessments is the allegation

21

here, that you had information from these previous

22

assessments about the material properties and the

23

processes that were recommended in 2004 that were not

24

applied.

25

MR. RANDOLPH:

So, you disagree with the

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Baker report because it says crack growth rates are not

2

affected by toughness?
MS. ATKINS:

3

I was looking at the very

4

first page of the report that identifies the four

5

factors for crack growth rates.
MR. RANDOLPH:

6

So, you disagree with

7

Kiefner saying crack growth rates are not affected by

8

toughness?
MS. ATKINS:

9

That's not what I said.

It's

10

the remaining size that's there that has to grow.

11

can survive the hydro test has to do with the toughness,

12

and toughness is one of the inputs in the Pipelife

13

model.

So, you have to know --

14

MR. RANDOLPH:

15

MS. ATKINS:

16

What

So, it was considered.
If it was considered, how was

it used?

17

MR. RANDOLPH:

18

MS. ATKINS:

In the model.
But the model is for fatigue

19

crack growth, which you've demonstrated repeatedly that

20

you have not had any fatigue crack growth.

21

no fatigue failures.

22

MR. RANDOLPH:

23

MS. ATKINS:

You've had

Right.
So, why would you continue to

24

use a reassessment interval and long seam failure

25

susceptibility determination process that relies on an
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experience that you aren't having?
MS. LITTLE:

2
3

To continually evaluate, to

ensure that something hasn't changed.
MS. ATKINS:

4

But there are other failure

5

mechanisms occurring.

Because if you have a failure at

6

a lower pressure than what was previously experienced,

7

it could be a pressure reversal.

8

environmental cracking.

9

related to the seam that is a manufacturing defect, and

It could be some

It could be hardness issues

10

the process as observed don't take those into the

11

decision process as risk factors for this pipe.
MR. HOGFOSS:

12

The record does show that

13

the Company considered all of those factors in its

14

engineering analyses.

15

them in his review of the metallurgy report that went in

16

with the --

John Kiefner certainly concluded

MS. ATKINS:

17

I don't see where he saw the

18

metallurgy report for the hydro test, though.

19

get those?

20
21
22
23
24
25

MR. KOETTING:

Did he

He's had those for a number

of years, and he has them for this.
MS. ATKINS:

Did he review them for the

purpose of this testimony?
MR. KOETTING:

He has reviewed them

multiple times.
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MR. HOGFOSS:

2

MS. ATKINS:

3

For the purpose of this

affidavit, did he review them?
MR. HOGFOSS:

4
5

But not only --

Yes.

He has all of that

information.

6

MR. KOETTING:

7

MS. ATKINS:

He has all of our data.
Because he was very specific

8

about what data he reviewed in his statement, and he

9

didn't mention those.
MR. HOGFOSS:

10

Here's a problem that occurs

11

to me.

12

before -- of dozens of engineers, including engineers

13

and experts recognized and hired by the Agency itself

14

that have all looked at this data, reached the same

15

conclusion.

16

disagree with all of them.

17

So, you have decades -- and I said this

And essentially you're telling us that you

MS. ATKINS:

I agree with many of the

18

statements in here.

19

as not being able to detect this.

20

you would be able to detect it is not our allegation.

21

And his previous studies said that the appropriate

22

assessment method would have been a hydrostatic test.

23

They're carefully qualified, such

MR. HOGFOSS:

Well, whether or not

Do you believe that if there

24

were no violations, if the Company did everything you

25

say they should have done -- which, in fact, we're
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showing in documents is that they did, in fact, do it.

2

It may not have been at the exact month that you're

3

saying, but they did more than required voluntarily.

4

Are you saying that if they had done it exactly the way

5

you predict, they would have found this defect?
MS. ATKINS:

6
7

allegations or suppositions -MR. HOGFOSS:

8
9

I am not making any

That's not important to the

Agency, then.
MS. ATKINS:

10

It's very important to us,

11

which is why we go back and look at the processes and

12

discuss what are apparent causal factors in any aspect

13

of a failure investigation.
MR. HOGFOSS:

14

What is the purpose of this

15

enforcement action, then, if it's not to point out these

16

violations?

MS. ATKINS:

17
18
19

Is it -Typically it's corrective

action.
MR. HOGFOSS:

Right.

So, again -- and I'm

20

honestly having a hard to time kind of matching this up.

21

The alleged violations, asking the Company to take

22

certain actions, in fact the Company did -- they did

23

consider P&M measures and putting in the EFRD's.

24

did run a seam tool, even though they concluded --

25

MS. ATKINS:

They

We need to get back to Item

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1.

2

MR. HOGFOSS:

3

MS. ATKINS:

4

MR. HOGFOSS:

We need to get

This is Item 1.

This all

relates -MS. ATKINS:

7
8

I'm sorry.

back to Item 1.

5
6

Excuse me.

Item 1 doesn't have P&M

measures in it.
MR. HOGFOSS:

9

This all relates to the fact

10

an incident occurred because -- a defect was not

11

detected.

12

takes the position -- it certainly implies in here for

13

the public that had the Company simply complied with the

14

law, this would not have happened.

15

carefully stated it so you're not saying that; but

16

that's why we're here contesting all of these nine

17

alleged violations, which is unusual after an incident

18

like this.

19

actually complying with the regs, its own procedures,

20

and doing more than required.

21

be how do we find the next one for all of us.

And we -- I find it troubling that the Agency

But it's also unusual that a company was

MR. SEELEY:

22
23

And the goal here should

I guess it seems to me we've

reached a point where we are disagreeing.
MR. HOGFOSS:

24
25

It's nice that you

I think we reached that in

our response.
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MR. SEELEY:

1

I think we're circling the

2

conversation around a disagreement that I don't know is

3

going to be resolved by continuing to say we disagree.
MR. WHITE:

4

But it might be helpful, Rod,

5

to just sort of understand about the risk factors that

6

are at issue here.

7

model had, let's say, ten risk factors on the list,

8

an ERW pipe, would it not be -- if you sort of weighted

9

those, I would think your top two or three would be, as

I mean, if a given pipeline risk

10

Bob said, third-party damage, corrosion and, you know --

11

in my experience, PHMSA has issued advisory bulletins

12

and we have seen multiple ERW failures on all kinds of

13

different ranges.
I would think, you know -- I think the

14
15

issue is that -- the allegation is that we were missing

16

one of the bigger higher-weighted top two or three type

17

of risk factors, and that skewed the model that was

18

being used.

19

guys have inspected and looked at these integrity

20

management programs, I would think that the majority of

21

operators with ERW would say are susceptible as part of

22

the risk model.

And so -- and all the operators that you

Is that accurate?

23

MR. SEELEY:

I don't know that I want to

24

draw in a generalization.

25

information -- if I had had the information -- I think

I mean, to me, the

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the information would point that this pipeline would

2

have been susceptible to the seam mechanisms that we've

3

talked about.

4

operator to pursue different lines of thinking and doing

5

different activities.

Having identified that will drive an

Each operator's going to have their own

6
7

risk factors and threats that are going to differ from

8

pipeline to pipeline.

9

is not necessarily what a different operator's threat

What your biggest threat may be

10

may be.

11

worst thing in the world, I don't know that I

12

necessarily want to state that.

13

So, to try to say those universally are the

It's just a point that in this allegation,

14

there are certain basic bits of information that were

15

present and available.

16

review of the integrity management analysis processes

17

that you go through, we could not determine that these

18

things were being utilized to drive the decisions within

19

your integrity management program.

20
21
22

And in our investigation and

MR. WHITE:

Despite the fact that test

failures had occurred and -MR. SEELEY:

Well, from what we can tell,

23

they did not utilize that information, some of the

24

information being pipe materials, toughness, some of the

25

information being hydrostatic test failures or
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historical test failures.

2

information that we don't see as being applied within

3

the processes.
MS. LITTLE:

4

So, they're all bits of

On the issue of the

5

hydrostatic test failures, I think, that's -- I mean,

6

we've provided information on that, that the Company

7

did, in fact, look at all those.

8

third-party expert to look at those.

9

2006.

They retained a
That's Hurst in

And that analysis, the result of it, was there

10

was no evidence of pressure cycle-induced fatigue,

11

selective seam corrosion or other time-dependent

12

defects.

MR. SEELEY:

13
14

They looked at all the failures specifically.
That goes back to the

whole --

15

MR. WHITE:

16

MR. SEELEY:

Hardness.
-- well toughness -- brittle

17

versus -- we're going back to those singular mechanisms

18

where your historical -- I think tests back before the

19

2005 or '6 testing, you had several in 2005 and 2006.

20

I'm going to say 11.

21

in --

Prior to that, there is a test

22

MS. ATKINS:

1991.

23

MR. SEELEY:

'91.

24

MS. ATKINS:

Had three.

25

MR. SEELEY:

We had three.

And prior to

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that, you had --

2

MS. ATKINS:

One in 1969.

3

MR. SEELEY:

So, you have one and three

4

and 11.

You're having a progression of these

5

seam-related failures during testing which would mean

6

there's something going on.

7

that is creating more of these throughout time.

8

yet, you seem to keep falling back to the model that

9

says they don't exist.
MS. LITTLE:

10

There's something changing
And,

They did when Hurst looked at

11

it.

And, Steve, correct me if I'm incorrect.

12

believe they looked at those differences between the

13

different hydro tests, correct?

14

MR. KOETTING:

15

MS. LITTLE:

16

MR. KOETTING:

But I

They did.
And?
One of the things that they

17

concluded was that the pipe failures in the most recent

18

hydro tests were due to a couple things, higher

19

pressures than had been seen which always causes more

20

failures, and the temperature of the test water was very

21

low.

22

more brittle.

So, it creates those brittle defects to be even

23

So, their conclusions from the hydro test

24

was that the combination of the low testing temperature

25

and the brittle nature of those defects and the higher
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test pressures would have caused the failures.
MR. SEELEY:

2
3

low, was it subzero?

4

range.

Your temperature water being

Was it freezing?

5

MS. LITTLE:

6

prior tests were in the 80s, 90s range.

7

significant difference.
MS. ATKINS:

8
9

There was a

It was in the 40s, and the
It's a

We took a long look at that

and we also looked at your conclusions and we looked at

10

the metallurgical analysis.

And you're still in the

11

lower shelf from zero to 95 degrees for the Charpy

12

testing.

13

regardless of temperature.

So, all of those values were three to four

So, those statements were potential.

14

They

15

were not conclusions.

16

variant testing didn't support that there was a

17

temperature change that changed the properties because

18

you tested the materials at zero, 35, 65 and 95 at

19

varying different metallurgical analyses in the

20

Charpy --

21
22

They were considerations, and the

MR. KOETTING:

survived, not the pipes that failed.

23

MS. ATKINS:

24

MR. KOETTING:

25

Those are the pipes that

Correct.
You can't test the seams

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MS. ATKINS:

2

MR. KOETTING:

3

MS. ATKINS:

There's no seam left.
Destroyed, yes.
However, there were portions

4

of the joint that were still there but still displayed

5

those low toughness values in a split where there was a

6

piece left.

7

much like what was done in this particular case.
Your statement in the current

8
9

Then they were able to test the toughness,

metallurgical report, which is in our Exhibit B to the

10

violation report and the first metallurgical Number

11

65961 on Page 3 says, Prior to failure, the pipeline was

12

reported to typically operate between 47 and 78.

13

the 40s is still in your normal operating pressure range

14

for the testing.

So,

So, it's sort of unclear as to how that

15
16

conclusion was drawn or if that conclusion is

17

appropriate.

18

of the integrity results by your integrity engineers

19

that couldn't determine whether the failure at the lower

20

pressure was actually due to the lower temperatures or

21

pressure reversals.

22

And it was later questioned in the summary

And so, there is not a conclusion that's

23

supported either by the metallurgical testing or your

24

own in-house documentation for that being the cause.

25

And when you fail at a lower pressure than previously
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subjected, you do have some sort of time-dependent

2

mechanism or some sort of stress that has occurred based

3

on what the failure looked like at the seams --

4

MR. KOETTING:

5

MS. ATKINS:

That's true.
-- whether it was the

6

previous hydro testing, whether it was some sort of

7

in-service stresses.

8

dependent that's occurring.

So, there's something time

We could probably conclude, as you did,

9
10

that there was no evidence of fatigue; but all the

11

reports qualified that the oxidation or the surface

12

appeared to be in a manner that they could not conclude

13

but they saw no evidence of fatigue.

14

everything that we looked at, we didn't see it either

15

because you couldn't have fatigue in that brittle

16

material.

17

material for it to act in that manner and for the

18

fatigue to occur.

20
21
22
23

It wouldn't -- you have to have ductile

MR. WHITE:

19

And from

Mary, do you have anything to

add?
MS. MCDANIEL:

I think Molly summarized

that very well.
MS. LITTLE:

Except that part of the

24

conclusion you're drawing or based on reports that were

25

issued post-incident and then applying it back to what
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might have been known when the Company was doing the

2

analyses at different points in time?

3

MS. ATKINS:

Excuse me?

4

MS. LITTLE:

Yeah.

5

You were just talking

about the most recent Hurst report.
MS. ATKINS:

6

I'm talking about the 2005,

7

2006 reports, all of those Charpy values are flat, all

8

in the three to five range for all temperatures; and it

9

was similar to this report, the current report.
So, I was drawing a similarity.

10

But we

11

looked at every one of the Hurst reports from the 2005,

12

2006, plotted it.

13

report is right in the middle of all the data, which is

14

on the low end, one to three, and high end, three to

15

five.

16

brittle failure, and it never got above ten percent

17

shear on those.

18

means the temperature would not have made a difference

19

for the brittleness.

20

of temperatures.

And the current one -- the current

And one of the properties is percent shear versus

So, it's in the lower shelf, which

It was brittle in that whole range

MR. RANDOLPH:

21

Let's start with the 2005,

22

2006 hydro test.

They weren't failing at a hundred

23

pounds or 200 pounds or 500 pounds less than the prior

24

hydro test.

25

since '91 or something else.

It was, like, eight, eight pounds over -That could be -- that

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could be a measurement discrepancy between being used

2

then.
MS. ATKINS:

3

Well, you would hope not

4

because your acceptance criteria for your pressure

5

testing is within that range.
MR. RANDOLPH:

6

It could have been have

7

factored in some.

It could have been less.

8

point being is between '91 and 2005 and 2006, you're not

9

seeing huge -- and then the ones that were above, say,

10

20, it was after that piece had already been pressured

11

up once, and it experienced the hydro test failure.

12

Well, then, the next one experienced the pressure

13

reversal from that exact test.
MS. ATKINS:

14

But the

So, I think it's --

What was the final percent

15

SMYS that you tested in that first segment, do you

16

recall?

17

SMYS?

18

in that first segment?

The successful hydro test, was it 72 percent
So, do you believe you got rid of all the cracks

19

MR. RANDOLPH:

Are you talking --

20

MR. KOETTING:

Do we believe we only had a

21
22
23
24
25

hundred percent of the hook cracks in the pipeline?
MS. ATKINS:

In that first segment.

Just

that first segment.
MR. KOETTING:

I don't believe it's

possible to remove a hundred percent of hook cracks with
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a hydro test.
MS. ATKINS:

2

Why did you accept a lower

3

test pressure than -- on that segment instead of

4

continuing to test to what your target pressure had

5

been?
MR. KOETTING:

6
7

to test to a certain -- pressure.

8

MS. ATKINS:

9

MR. KOETTING:

10

I'm just curious.
-- pressure.

They say we

have to --

11

MS. ATKINS:

12

MR. KOETTING:

13

The rules don't say we have

You had a plan and -We have to set our maximum

operating pressure as a percent.
MS. ATKINS:

14

You had a plan and a design

15

to test to a certain level and you had four test

16

failures in the seam and then you tested at a lower

17

pressure.

18

MR. KOETTING:

19

MS. ATKINS:

20
21

Yeah.
Why -- there was a decision

process.
MR. KOETTING:

In any hydro test, you try

22

to decide, are you doing good or are you doing damage

23

during the time.

24

that are significant enough -- even today when we set up

25

a hydro test, we would consider, are we doing harm to

If you experience pressure reversals

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the pipeline by continuing to try to test it?

2

back off from it?

3

goes through.

That's a process that every operator

We don't just keep testing pipe until we

4
5

destroy the whole thing.

6

acceptable test.

We test pipe until we get an

7

MS. ATKINS:

8

MR. KOETTING:

9

So, would you test -The regulations would be

really, really nice.
MR. SEELEY:

10
11

Should we

I think we're sort of

wandering off.

12

MR. KOETTING:

13

MR. SEELEY:

Well, good.
I think we've circled on the

14

issue several times.

15

disagreement on the position.

16

it because then you'll restate it and we'll go down the

17

conversation again.

18

conclusions or comments we can make in our

19

recommendations after the hearing.

20

yours, and we'll make ours.

21

Surprisingly, there's a
I'm not going to restate

So, I think maybe any other

MR. HOGFOSS:

And you could make

Just in summary, though, to

22

respond to that one comment you made without trying to

23

open it up again, I don't think anyone would disagree

24

with the statement you said as a general rule if an

25

operator concludes that there's not a susceptibility to
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seam failure, then that operator might not pursue the

2

threat it would otherwise identify.

3

obvious general statement.

That's a pretty

But in contrast, just to say again, in

4
5

this instance, the operator actually did keep looking at

6

these issues, ultimately ran a crack tool.

7

final note, that, you know, hindsight really does work

8

both ways.

Clearly we are here because there was an

9

incident.

And after the incident, the Agency took a

And just a

10

very close look at all of these issues, the same issues

11

that the Region did not identify as a concern in a very

12

in-depth 2007 audit when the Company had concluded this

13

line was not susceptible to seam failure then.

14

All we're saying is that we ask you in

15

your hindsight to also look at what the Company did do.

16

So, they did not just reach that conclusion and do

17

nothing further.

18

ultimately ran the crack tool.

19

focused on that, what can be done, what should be done,

20

how can the Agency and the industry work together in the

21

future on this.

22

They did keep looking.

They

So, we're trying to stay

But I think that's it for Item 1.

MS. ATKINS:

There is another potential

23

risk that's not addressed because one of the questions

24

in the TIARA model is is it susceptible or not.

25

whether you answer yes or no would create identified

And

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threats.

So, in the areas where there's seamless pipe,

2

you wouldn't answer that yes.

3

testable -- that portion of the testable segment

4

wouldn't have that answer.

So, that segment of the

But the risk model asks the question if

5
6

it's been considered; and it, again, weights the factors

7

that creates identified threats.

8

other risks that doesn't get identified in the

9

identified threat process in the TIARA model.

10
11

Which is not part of NOPV

MS. ATKINS:

It's part of considering the

risk.
MR. WHITE:

14
15

MS. LITTLE:
Item 1.

12
13

So, this is one of the

All right.

I think that's all

we have on Item 1.
MR. KOETTING:

16

One last thing I'd like to

17

say.

18

for choosing the tool that we chose to assess the seam.

19

We're not in-line inspection companies.

20

inspection companies to assess our pipe.

21

chose was the tool that PII has in their crack

22

management that's capable of identifying selected seam

23

corrosion in ERW seam.

24
25

The tool that we chose -- we've been criticized

We hire in-line
The tool we

It was the recommended tool.

MS. ATKINS:

It's certainly appropriate

for selective seam corrosion.
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MR. KOETTING:

2

MS. ATKINS:

3

MR. KOETTING:

4

Of a certain size.
Regarding the best

documents we had, it was the tool.
MS. ATKINS:

5
6

And ERW seam defects.

Of a certain size, would you

agree to that?

7

MR. KOETTING:

8

MS. ATKINS:

9

MR. KOETTING:

Of a certain size -A specified size -Any defect is of a certain

10

size.

A UT crack detection tool is of a certain size.

11

A corrosion tool is of a certain size.

12

that we ran the wrong tool would be to say we got the

13

wrong guidance from our in-line inspection company.

14

MS. ATKINS:

15

selective seam corrosion.

16

lot of things.

17

MR. KOETTING:

18

MR. SEELEY:

19

MR. HOGFOSS:

So, to imply

You ran the right tool for
You ran the right tool for a

Which was a higher risk.
Okay.
Actually, because this is

20

such an important point -- and we noted it before -- but

21

the violation report actually does say that you ran the

22

wrong tool.

23

there isn't anything in the law to support that.

24

There's not even any guidance out there to support that.

25

You should have done the UT or an EMAT, and

MS. ATKINS:

The defect type and size for

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the previous integrity assessments that you knew existed

2

in the hook cracks is part of 1(i).

3

previous integrity assessment, defect type and size.

4

And with the crack opening widths that were in those

5

metallurgical reports, it had not been detected because

6

they were less than one millimeter.
MR. HOGFOSS:

7
8

disagree on that.

10

But also --

It might be in the accident

report, but I don't believe it's in the NOPV.
MR. HOGFOSS:

11
12

To quote -- to quote Rod, we

It's not in the law.

MS. ATKINS:

9

Results of the

It's not in the NOPV.

It's

in the --

13

MS. ATKINS:

14

MR. HOGFOSS:

-- so I'm sorry.
But related in that same

15

area, though, just to note this for the record as well,

16

because in that same area, it says clearly -- it makes

17

this broad conclusion that the comp- -- that the Company

18

failed to consider pipeline safety.

19

statements like that, and we just would like to note for

20

the record that we obviously strongly object to this.

21

This is a company that does do more than the minimal

22

required and that's a very sweeping, and we think

23

irrelevant and absolutely completely unwarranted,

24

statement.

25

There's a lot of

There's quite a few of them.
THE HEARING OFFICER:

Okay.

It sounds

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like we've wrapped up Item 1.

2

sort of incorporate a lot of the discussion we just had.

3

So, I think that those items will move a little bit more

4

quickly.

But why don't we try to -MR. SEELEY:

5

I know Items 2 through 4

Yeah.

Item 2 has to go [sic]

6

with the reassessment interval requirement of -- there

7

was no performance of the assessment of the line within

8

the allocated time frame of five years, not to exceed 68

9

months, within the regulations.

10

THE HEARING OFFICER:

11

MS. LITTLE:

Thanks.

Obviously this relates back

12

to NOPV Item 1, so without opening up that door again

13

but just to -- because we think and it's our position

14

that the Company did, in fact, properly assess the risks

15

on the Pegasus Pipeline and properly did determine that

16

the line was not seam susceptible multiple times.
We said before the Agency's had plenty of

17
18

opportunities to review that and did, in fact, review it

19

in-depth how the Company was conducting that analysis in

20

2007.

21

line was not susceptible to longitudinal seam failure,

22

given that conclusion, there's no requirement that a

23

seam tool be scheduled within five years.

24

that the IMP works, if a pipe is susceptible to seam

25

failure, then they are required to run an assessment

But because the Company did determine that the

So, the way

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tool every five years and --

2

MR. SEELEY:

Perform an assessment.

3

MS. LITTLE:

Thank you.

Perform an

4

assessment and then determine what the reassessment

5

interval would be.

6

not required based on that seam susceptibility analysis,

7

there was no specified time period.

8

really no five-year assessment interval to be

9

established.

But in this instance, because it was

Therefore, there's

10

Even though, you know, the rules don't

11

require that an operator reassess a line with a seam

12

tool every five years, just because ERW pipe is present,

13

you have the make the determination that it's seam

14

susceptible.

15

IMP regulations, reassessed the line in 2010 as part of

16

its program within four years of the prior assessment.

17

And the Company made a determination that they wanted to

18

go ahead and run a seam/crack tool anyway, really

19

consistent with the Baker report.

So, the Company, in compliance with the

20

And frankly, the basic tenets of a

21

program, that companies gain information, gather

22

information, continually assess.

23

says, you know, have the best available information you

24

can have.

25

more information on the line.

Even the Baker report

So, the Company wanted to run the tool to get
And they thought it was

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the prudent thing to do, and that's why they did it.

2

But it was not subject to a five-year assessment

3

interval.
THE HEARING OFFICER:

4

So, just to clarify,

5

you're not saying that there was no five-year

6

reassessment interval.

7

five-year reassessment interval to run the TFI tool.

You're saying that there's no

8

MS. LITTLE:

9

MR. HOGFOSS:

10

For seam -For certain -- or crack

tool.

11

MS. LITTLE:

12

THE HEARING OFFICER:

13

That's right.
For running a crack

tool?

14

MS. LITTLE:

Correct.

15

MR. SEELEY:

Yeah.

I didn't hear a

16

dispute of the particular facts of assessments, dates.

17

I don't think we're disputing which assessments were run

18

when.

19

seam assessment was required sooner than it was

20

performed.

21

we had in Item 1 that it would have been.

22

that there's any relevant --

23

I think the disagreement is whether or not the

And we would contend based of the discussion

MS. ATKINS:

I don't know

There's just one other item.

24

That's the data integration team recommended in 2009

25

that in 2010 the TFI tool be run in combination with the
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combo tool or the caliper or metal loss tool.

2

don't understand what happened from then, that it was

3

then scheduled for 2011 when the 2011 communications

4

[sic] was changed to 2012 for budget reasons.
MS. LITTLE:

5

Well, two things.

And so, I

Number

6

one, the timing within which to conduct that tool run

7

was actually the recommended timing was that it be run

8

before 2013.

So, it was not specified that it had to be

9

run in 2011.

And I think initially -- so, in fact, I

10

think even under Pipelife, the way in which -- and

11

you-all correct me if I'm wrong -- but the way in which

12

it determines what that interval is going to be, it's

13

really based on half-life.

14

conservative to say it has to be run by 2013.

15

was well within the time that the Company had in their

16

minds to run this tool, which they were running

17

voluntarily anyway.

18

So, that's even very
So, it

In terms of the -- in terms of the reason

19

to extend it, I don't think it was for budget reasons.

20

It was not for budget reasons.

21

MS. ATKINS:

Actually it was.

Just a

22

moment and I'll find it.

From 2011 to 2012, it was.

23

But in 2009, the recommendation for 2010, I don't

24

understand what process occurred that the recommendation

25

from the data integration team was not taken.

Is there

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a process where somebody else reviews their

2

recommendation and then decides that, no, we're not

3

going to do it?
MS. JONES:

4

As I recall, the

5

recommendation from the risk and integrity specialists,

6

it was to run the TFI tool in the first half of the

7

line, analyze those results and then make a decision as

8

to whether we would run it in the second half of the

9

line.

We came back in those recommendations and said,

10

now we recommend you run it in the second half of the

11

line.
MR. WHITE:

12

Molly, What was your basis for

13

bringing up the point about the budget?

14

MS. ATKINS:

15

MR. WHITE:

16

Okay.

Are you looking at one

of the exhibits?
MS. ATKINS:

17
18

It was in the MOC.

Yeah.

I'm sorry.

I'll try

to find it.
MR. HOGFOSS:

19

But, again, Molly, I think

20

the important thing is -- well, two things.

One is that

21

that's not really an alleged violation.

22

think we have a clear understanding and disagree on this

23

point.

24

to run the crack tool was a management decision that was

25

not a required run.

As Rod says, I

But from the Company's perspective, the decision

It was a voluntary run.

They were

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doing more than was necessary.
So, therefore, it doesn't link to -- Rod

2
3

said, we're not in disagreement.

4

to do a reassessment in five years.

5

done.

6

decision as to whether or not to run a crack tool, and

7

that was being done voluntarily.

8

to the timeline.

That was being

It was actually being done early.

MR. WHITE:

9

MR. HOGFOSS:

10
11

There's a obligation

A separate

So, it wasn't subject

Let me just make a -That's a point of

disagreement.
MR. WHITE:

12

Let me just clarify one point

13

about that, which is, you know, the regulation that was

14

cited here is 195.452(J)(3); and that talks about the 68

15

months that was exceeded.

16

in evaluating this requirement, I think it sheds light

17

to go down to Paragraph (J)(5).

18

assessment methods.

19

operator must assess the integrity of the line pipe by

20

any of the following methods.

21

selects to assess low-frequency electric-resistance

22

welded pipe or lapwelded pipe to susceptible

23

longitudinal seam failure must be capable of assessing

24

seam integrity and detecting corrosion and information

25

anomalies."

But if you -- if you -- and

(J)(5) talks about

And 195.452(J)(5) says, quote, "An

The methods an operator

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So, what that -- what that tells me is

1
2

there's a general principle in integrity management that

3

says you must select the tool matched to the type of

4

risk that you're assessing.

5

goes on to specify that calls out low-frequency

6

electric-resistence welded pipe and calls it out

7

specifically.

So -MR. HOGFOSS:

8
9

And then -- and then it

It calls it out, but it

says, if deemed susceptible.

The rule could say -- the

10

rule could say all ERW pipe shall be tested with a seam

11

and crack tool, period.
MR. KOETTING:

12
13

Or hydro test on some

basis.
MR. HOGFOSS:

14

Right, at a certain level of

15

hydro test.

Or the rule could say all ERW pipe shall be

16

replaced within -- by the following date, but it

17

doesn't.
MR. SEELEY:

18
19

That's not a recommended rule

change, is it?

20

MR. HOGFOSS:

No.

21

MR. KOETTING:

22

MR. HOGFOSS:

Well, it is --

Not from our side anyway.
I'm just saying that the

23

rules could say different things, but they really are --

24

we're dealing with the rules as they are currently.

25

MR. WHITE:

I am as well.

I am as well.

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And the second point I want to make -MR. HOGFOSS:

2

But the key point is deemed

3

susceptible, and that's the point of disagreement.

4

did not deem it susceptible.
MR. WHITE:

5

We

The second point I just want

6

to make is what makes Item 2 separate from Item 1 is the

7

allegation in Item 1 deals with failing to account for

8

ERW in your overall risk model that you're using for

9

your program.

The allegation in Item 2 deals

10

specifically with this determining the reassessment.

11

Once the baseline has been done, that's all that's done.

12

Item 2 deals with determining the reassessment interval,

13

which is a sort of separate task.

14

point that out.
MS. LITTLE:

15

So, I just wanted to

That's right.

But it's a

16

separate -- the way in which it's alleged, it's the

17

reassessment interval after you've determined that

18

you're susceptible to seam failure.

19

part that we're in disagreement over.

20

we're not in disagreement over.

21

establish a five-year assessment interval would be

22

required.

23

we don't think the line -- we did not deem it to be

24

susceptible to seam failure and don't think it was.

25

And it's the latter
What the law says

But in terms of how you

But what we're disputing is that the line --

MS. ATKINS:

The --

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MR. SEELEY:

Okay.

2

MS. ATKINS:

-- information that I was

3

referring to is in our violation report Appendix A-M,

4

Appendix B and it's EMPCo Bates Stamped 017725.

5

The 7/18/2000 form dated 11/15/2011.

6

originally planned for the 2011 calendar year but is

7

being rescheduled for 2012 in an effort to maintain the

8

company's fiscal goals."

9

MS. JONES:

10

It's

"The tool run was

And what else does that

document go on to say?
MS. ATKINS:

11

"The change in date does not

12

cause any safety, health or environmental issues related

13

to the pipeline segment within the Pegasus crude

14

system."
MS. JONES:

15

Does it not also refer to the

16

reinspection interval that had been calculated once that

17

decision was made?
MS. ATKINS:

18

Well, the pipeline fatigue

19

analysis is the one we still say that you're

20

experiencing crack growth in a ductile manner.

21

method is one that we questioned in Item 1.

22

basis for the reassessment was using Pipelife.

23

we're saying that that is not the appropriate basis

24

or --

25

MS. LITTLE:

So, that

So, the
And

But the basis for the

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Company's decision is that, number one, they were

2

voluntarily choosing to run that line -- I mean, that

3

tool.

4

needed to be run by 2013.

5

established at a half-life, if you will.

6

conservative time frame anyway.

7

noted, it goes back to the original issue for Number 1

8

but --

Number two, the tool needed to be run between -Even that time period was
So, that's a

And, yes, just as Molly

9

MR. SEELEY:

Okay.

10

MS. LITTLE:

-- I think we can conclude.

11

THE HEARING OFFICER:

12

MS. LITTLE:

13

Do we have anything else we

want to add?
THE HEARING OFFICER:

14
15

Anything else --

-- to Item 2 before

we move to Item 3?
MR. SEELEY:

16

Item 3 is probably going to

17

carry a similar conversation.

This has to do with not

18

following procedure 5.1.

19

varies from their five-year interval, they must perform

20

certain action.

21

the assessment period for the ILI runs that we were just

22

talking about.

This is when the operator

And this goes back to, again, changing

23

THE HEARING OFFICER:

24

MR. HOGFOSS:

25

the same point with Item 2.

Okay.

And similarly, it really is
Since the Company concluded

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that the pipe was not susceptible to seam failure, it

2

was not -- it had not triggered a timeline in which to

3

run a seam tool.

4

Company was doing reassessments within the proper

5

intervals.

6

assessment after the 2010 ILI, wasn't due until 2015.

7

They elected -- voluntarily, not required -- to run a

8

crack tool prior to that.

9

wasn't required, it wasn't subject to a variance

There's no dispute, I think, that the

And in fact, they'd done the necessary

10

requirement.

11

add to that.

But since we believe it

And I think that's really all we have to

12

MR. SEELEY:

All right.

13

THE HEARING OFFICER:

14

MR. SEELEY:

We're done.

Item 4?

Item 4 has to go [sic] with

15

the prioritization of the assessments in which the

16

operator had assessed a section -- they assessed a

17

Patoka to Conway segment prior to the Corsicana to

18

Conway segment even though the Patoka to Conway segment

19

had less -- or in other words, the Corsicana to Conway

20

segment had more risks or risk values than the other

21

segment.

22

to the higher risk section.

So, they assessed the lower risk section prior

23

THE HEARING OFFICER:

24

MS. LITTLE:

25

Okay.

I think the important point,

I guess just to step back, the IMP rules require a
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process for prioritization of segments for reassessment.

2

They don't dictate the way the risk scores

3

prioritization for a particular segment, but they allow

4

operators discretion in making those determinations.

5

So, when it comes to the Pegasus Pipeline -- and I think

6

Muhlbauer speaks to this in his exhibit and in his

7

affidavits in Paragraphs 11 and 12 -- the Company did

8

consider all the risk factors and the risk conditions on

9

the pipeline when it scheduled the 2010 reassessments.
And as we've said before, the Company's

10
11

also determined that there are no segments that were

12

seam susceptible [sic].

13

the two different segments were practically identical

14

and indicated the probabilty of failure on either

15

segment was unlikely -- very unlikely.

16

to do the Patoka to Conway segment first -- and, Steve,

17

and Johnita, speak up if I misspeak on this -- but was

18

really based on four different points.

So, the 2007 risk scores for

And the decision

One, there were more hydrostatic seam

19
20

failures on an LF-ERW per mile basis on that segment.

21

There were more pressure reversals seen on that segment.

22

There was a shorter theoretical fatigue life based on

23

the existing data, and there were three girth welds

24

[sic] that weren't present on the Conway to Corsicana

25

segment.
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And that was the basis for running the

1
2

segments in the order in which they made them.

3

MR. KOETTING:

4

THE HEARING OFFICER:

5

That's true.
Anything in response

to that?

6

MS. ATKINS:

No.

7

MR. SEELEY:

We'll save it for the

8

recommendation.
THE HEARING OFFICER:

9
10

the conclusion of Items 1 through 9.
MR. SEELEY:

11
12
13
14
15
16

So, that takes us to

We're not going back through

5.
MR. HOGFOSS:

No.

We're not going to

start over with 5.
THE HEARING OFFICER:
covered 1 through 9.

I think we've

You can't go back on that.

17

MR. WHITE:

18

actually not have to go through lunch.

19

Sounds like this hearing may

THE HEARING OFFICER:

20

that up to you.

21

penalty and the compliance order --

22
23
24
25

I was going to open

If we were going to talk about the

MR. HOGFOSS:

That's relatively brief.

I

think if we took a short break, we can conclude it.
THE HEARING OFFICER:

Okay.

Let's take a

short ten-minute break.
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(Recess from 11:38 a.m. to 11:50 a.m.)

2

THE HEARING OFFICER:

We're going back on

3

the record.

4

Items 1 through 9, and I believe there's going to be

5

some discussion of the proposed civil penalty and the

6

proposed compliance order.

7

to start the discussion?

Bob, Catherine, do you want

MR. HOGFOSS:

8
9

We just finished concluding discussion of

the Region?

Should we start instead of

Do you think -MR. SEELEY:

10

I'll state my statement.

We

11

provide -- the process that we go through is we fill out

12

the violation report and the enforcement office

13

calculates a penalty based off of the information in

14

that report.

15

value or something of that nature, those are more

16

appropriate to discuss with the enforcement office,

17

which is now represented by Cliff on the phone.

So, if your questions are related to the

18

MR. WHITE:

19

MR. SEELEY:

20

MR. HOGFOSS:

25

And I don't think this will

take that long, but we'll -MS. LITTLE:

23
24

The penalty part, we're just

sort of a third-party here.

21
22

The compliance order we can --

Make sure he can hear you on

the phone.
MR. HOGFOSS:

Cliff, can you hear?

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MR. ZIMMERMAN:

2

MR. HOGFOSS:

I can hear you.
All right.

Good.

Well, to

3

begin and to summarize our discussion -- and this is in

4

our pre-hearing materials as well -- as we said earlier,

5

because there is no strict liability provision in the

6

Pipeline Safety Act, the occurrence of an incident

7

itself is not a basis for a violation or a penalty.

8

believe the Company was in compliance with applicable

9

rules; and, thus, simply because there was an incident,

10

we believe that there should be no violation and should

11

be no penalty.

We

But in the alternative, even if a

12
13

violation was deemed to have occurred, we find that the

14

amount of penalty is unwarranted and for two reasons

15

primarily.

16

of the claims are related as in the statutory language

17

which is picked up by the regulations at part 190 that

18

limits a related series of violations to a combined

19

penalty cap of no more than $1 million for incidents

20

occurring prior to January 3rd of 2012.

21

The first relates to the fact that several

And then the second reason really goes to

22

we think there wasn't an adequate consideration of

23

mitigation factors.

24

related series of violations, this language really came

25

in in the 2002 PIPES Amendments which really authored

To talk just for a moment about the

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the IMP amendments, regulatory [sic] as well.

2

really is no legislative history to that phrase,

3

"related series of violations," other than a snippet of

4

discussion between Senators Kerry and Senators Hollings

5

who stated that their understanding of what a related

6

series of violation should mean in the Pipeline Safety

7

Act would be to be in regard to a single incident.
Under that approach, we would think that

8
9

And there

this entire NOPV should be limited to a cap of

10

$1 million.

11

in 2009 and for the first time addressed this issue in a

12

decision called Colorado Interstate Gas, CIG decision,

13

and concluded in that case that related series of

14

violations should mean either multiple daily violations

15

of the same requirements or where the facts in the law

16

for multiple claims -- and this is quoting from the

17

decision -- "are so closely related that they are not

18

separate and should be considered one violation."

19

But beyond that, the Agency then went ahead

Our position is that Items 1 through 4 --

20

and really Items 7 and 8 based on our discussion here

21

today -- are clearly related because they all rely on

22

the same facts and law.

23

Company failed to consider that the segment was

24

susceptible to seam failure really is the linchpin under

25

each of those alleged violations, I think as

The NOPV's assertion that the

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demonstrated by our discussion, that they're so nested,

2

certainly 1 through 4; and really you need the premise

3

of 1 to reach 7.
So, for that reason, we think that those

4
5

violations clearly are related as the statute intended,

6

as the regs intended and as the CIG decision interpreted

7

because they do rely on the same facts and law.

8

thus, they should be in combination subject to no more

9

than a million-dollar combined penalty.

And,

10

And finally we note that in the Pipeline

11

Safety Violation Report -- we should also note -- this

12

is in your pre-hearing materials -- it's unusual that a

13

federal agency does not have a written penalty policy

14

and typically a matrix that says this is how we intend

15

to apply our statutory factors as to what the different

16

components should be.
PHMSA in the last few years started

17
18

working with the matrix of the Pipeline Safety Violation

19

Report.

20

they picked up some of the elements; but they don't

21

really show how they would apply as other agencies do.

22

And there's really no guidance out there.

23

presented at a hearing with a one-page document that

24

indicated it was a working draft of a penalty policy,

25

but we haven't seen anything since then.

Prior to that, there was really nothing.

So,

We have been

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So, there's very little guidance out there

1
2

other than looking at decisions as to how the Agency's

3

statutory penalty authority should apply, but it is in

4

the statute that the agencies should consider such

5

factors as good faith, cooperation and mitigation.

6

we don't see that addressed in the violation report as

7

mitigating factors.

8

clearly that in this case, the Company has shown good

9

faith in stepping up to the plate from the moment the

And

And we believe the record shows

10

incident occurred, working with PHMSA extensively, and

11

will be working with PHMSA extensively.

12

obviously has done considerable mitigation and will do

13

more.

14

actions, we believe, in advance of the incident, which

15

unfortunately failed to prevent it.

16
17

And the Company

As we discussed, they also took mitigative

So, I think that is the summary.
Catherine, anything else?

Johnnie?

18

And in short, we think that -- we think

19

that there should be no violations, thus, no penalty.

20

But in the alternative, we think at a minimum Items 1

21

through 4 should be grouped as a related series of

22

violations, and 7, that's really inextricable, and

23

penalty adjusted.

24
25

THE HEARING OFFICER:

Okay.

Cliff or

anyone else from OPS have any comments in response?
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MR. SEELEY:

1

No.

I think -- we don't have

2

any particular thing.

I think we can address some of

3

that stuff in the recommendation.

4

THE HEARING OFFICER:

All right.

5

MR. ZIMMERMAN:

Yes.

I couldn't hear that

THE HEARING OFFICER:

Mr. Seeley just said

6

Cliff?

response.

7
8

that he could address some of that in his post-hearing

9

response.

10

I just wanted to make sure you didn't have

anything else to add before we move on.
MR. ZIMMERMAN:

11

No.

I really don't at

12

this point.

13

the penalty based on the evidence as presented in the

14

violation report and the NOPV.

15

it.

16

We do the violation -- you know, calculate

MR. WHITE:

So, that's the way we do

I will make one kind of quick

17

point, which is that, you know, one of the things that

18

has happened today, as we've sat down and we've sort of

19

discussed the alleged violations and ExxonMobil has kind

20

of given us their side of things, there may well -- you

21

know -- and we have filled out the record here, in fact.

22

There may be some mitigating points that would warrant

23

some degree of adjustment to the penalty.

24

that's the purpose for these hearings.

25

So, I mean,

And so, we're not reflexively opposed to
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that sort of thing.

That's -- and as a matter of fact,

2

the amount -- the proposed penalty amount for each one

3

of these items in the notice, in the NOPV letter, is

4

just that, it's just sort of a initial proposed kind of

5

starting point, if you will.

6

giving the operator sort of a ceiling or a cap so that

7

it knows what the stakes are in the case.

It fills the function of

But the -- the actual final penalty amount

8
9

is not set really until the Hearing Officer produces

10

the -- and Associate Administrator produce the final

11

order.

12

surprising that the penalty amount initially proposed --

13

you know, that's based on the Agency's investigation and

14

certain preliminary findings in the investigation.

15

you know, there's nothing wrong with the fact that

16

you've already heard today there may be some explanatory

17

things that should also be factored in.

18

make a point that the penalty isn't a final penalty

19

until after this hearing process takes place.

20

So, I just make the point that it's not

THE HEARING OFFICER:

21

compliance order.

22

introduce in the compliance order?

23

And,

So, just to

Okay.

On to the

Is there anything OPS would like to

MR. SEELEY:

Not particularly.

I don't

24

want to read all the items.

Basically there were

25

several items that were identified obviously in the
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notice.

And the compliance order is basically the, A,

2

you know, you're in violation accusation; so, B, stop

3

being that way, through these different actions, I

4

guess.

5

THE HEARING OFFICER:

6

MS. LITTLE:

Okay.

Okay.
I think really just

7

two primary points to make with respect to their

8

proposed compliance order.

9

the proposed compliance order requires review and

The first -- Paragraph 1 of

10

revision of ExxonMobil Pipeline Company's IMP plan for

11

all pre-1970 ERW pipe assets of the company.

12

proposed compliance order essentially, you know, is

13

injunctive relief for the Agency.

14

what it stands for, corrective action that the Agency

15

thinks an operator needs to take.

16

And the

That's essentially

There's a lot of federal case law on the

17

very issue of how administrative agencies develop and

18

propose or implement their injunctive relief, how it

19

should be -- how it should be presented.

20

law is pretty well settled that agencies should narrowly

21

tailor their injunctive relief to the specific harm

22

alleged, not to potential harm.

23

And the case

And with that sort of proposed parameters,

24

if you will, we think that that first paragraph is too

25

broad and extends really an incident-specific NOPV to
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apply to other assets inappropriately.

And it goes to

2

some issues that we, believe it or not, haven't spent a

3

lot of time on yet today.

4

particular pipe at the failure location had unusual pipe

5

properties and are distinct from others.

6

reason, we think it should be limited.

But this incident, this

And for that

I think the second primary point that we

7
8

want to make has to do with just a lot of the other

9

elements on there, I guess.

The IMP rules themselves,

10

as you all know, require continual evaluation of

11

pipeline integrity management, and that's certainly

12

ExxonMobil Pipeline Company's obligation.

13

of that and as part of being a good operator, they're

14

already reviewing and revising their IMP plan as

15

appropriate based on the incident.

And as part

And so, a lot of the actions that are in

16
17

the proposed compliance order to some degree are already

18

underway.

19

exception of the Paragraph 1, I think a lot of those

20

elements are already -- they expect that they'll be able

21

to address all of those particular elements.

22

think the bottom line is that we object to it being

23

overly broad given the fact that the agencies are

24

required to narrowly tailor their injunctive relief.

25

And I think that you-all -- with the

THE HEARING OFFICER:

But I

Okay.

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MR. SEELEY:

1

I think part of the broadness

2

that may be here is this is dealing with your integrity

3

management plan and things you do.

4

is you have a singular plan that you utilize.

5

kind of difficult to know when you're asking for

6

modifications to a singular plan to say but only do it

7

for this pipeline because it becomes your plan for all

8

of your assets by default.

And my understanding
So, it's

So, you're kind of not able to do what you

9
10

just say.

Because if you modify your plan, it modifies

11

it for the whole company, unless you're going to start

12

creating multiple plans.

13

intent.

I don't think that's your

So, it's kind of an impossibility.

14

MS. LITTLE:

I think --

15

MS. ATKINS:

We also had -- in looking at

16

the annual reports for both ExxonMobil and Mobil,

17

80 percent of the pipeline miles are pre-70 ERW.

18

it's a significant amount of the pipeline.

So,

There have been three seam failures on the

19
20

ExxonMobil assets in this region that we have

21

investigated, and this is the fourth seam failure under

22

this integrity management plan that has determined

23

through the investigation and analysis conducted by

24

ExxonMobil that it is somehow unique and an isolated

25

event.

And as such, it has kept -- that root cause
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failure analysis type of decision has kept the processes

2

from being reviewed.

3

So, in looking at that, the broadness that

4

we're seeing in this region through the other ExxonMobil

5

[sic] that we included in our discussion in Appendix B,

6

that those conclusions continue to focus on unique

7

isolated events instead of looking at the processes.

8

So, that would be the broadness that would pull in --

9

what this plan covers is broad.
MR. HOGFOSS:

10

If I could say a few things

11

in response to that.

First, as shown in this incident

12

and on its entire system, the company does more than the

13

minimally required.

14

conclusion that a segment of pipe is not seam

15

susceptible, it's still looking at those issues.

16

talked about that before.

Thus, even if it reaches that

We

Second -- and we note this in our -- and

17
18

Catherine noted it -- the Company already is -- because

19

that's what good operators should do already is looking

20

at what may be appropriate to revise as far as written

21

procedures.

22

of your obligation under IMP.

23

a final order and a compliance order on that, and I

24

think that goes to Rod's point as well.

25

And we understand that that -- that's part
We don't need to wait for

But, you know, to the extent -- and your
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point, Molly -- to the extent that there are common

2

issues, of course the Company's going to look at common,

3

where appropriate, provisions.

4

underway.

5

seen that before where a compliance order -- and it may

6

be moot as Rod says.

7

where we've seen a specific incident -- pipeline then

8

apply proposed relief to an entire company's assets.

9

So, we do ask that that still be open for -- that we are

10

So, that process is

But finally, we do know -- because we've not

I don't know for certain -- but

contesting that.
And ultimately, if a final order is issued

11
12

with a compliance order as it is now intact, I guess we

13

presume that the Region, as it usually is, would be

14

willing to discuss the timing of deadlines of certain

15

things because some of the things are pretty crammed

16

together in there.

17

appropriate, but then 120 days may be a short time to

18

document everything.

19

experience that's the type of thing --

And one 30-day requirement may be

But we presume based on past

MR. SEELEY:

20

Typically that would be

21

addressed within the final order.

22

alternative to say if you need to adjust variances, you

23

submit it.

24
25

There's typically an

So, that's normal.
MR. HOGFOSS:

And we'll raise any of those

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MR. SEELEY:

1
2

and you will tell us when we're wrong.
MR. HOGFOSS:

3
4

Take our best timeline guess,

I believe -- any other --

Johnnie, anything else on that?

5

MR. RANDOLPH:

6

MS. JONES:

7

THE HEARING OFFICER:

8

not -- okay.

No.
Anything else about

Go ahead.
MR. WHITE:

9

No.

Just one sort of quick

10

follow-up on the compliance.

Catherine described it as

11

injunctive relief.

12

differently, which is a compliance order has only really

13

one purpose, which is -- which is just to achieve

14

compliance with existing code requirements.

I would describe it slightly

So, for example, we couldn't put in a

15
16

compliance order asking a company to go above and beyond

17

the code requirements in the same way that, you know,

18

somebody might think of injunctive relief as kind of

19

a -- you know, when there's a spill as a sort of a

20

running slate to come up with different injunctive

21

things that somebody might think might help the

22

situation.

23

So, I just want to point out that the way

24

we use compliance orders, it's for just a limited

25

purpose of having the Company just achieve code
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compliance, nothing more and nothing less, by the way.

2

We never do a compliance order -- we couldn't have a

3

term in there that says you shall do something less than

4

the code.

5

and -- in the manner of having some sort of a plan and

6

timelines and things like that.

7

Similarly, it's just to achieve the code

So -- and, you know, if there is some --

8

if you think that there is some aspect of this

9

particular proposed compliance order that is asking the

10

Company to go above and beyond the code requirement, you

11

know, you're free to sort of note that in your proposed

12

hearing response.

13

out may, if it -- if your -- if you are persuasive, it

14

may adjust the compliance order for that reason.

15

There's nothing wrong with that if that happens.

16

And then the final order that comes

MS. ATKINS:

But where there are internal

17

processes, it's not above and beyond adherence to an

18

existing internal process.

19

MR. WHITE:

That's right.

Rod's point

20

still stands, that all we can do is say -- whatever plan

21

you're using for this pipeline -- let's assume it needs

22

to come into compliance -- the fact that the Company

23

applies that -- the breadth and the scope to which the

24

Company applies that plan to its other pipeline is not

25

something that's within the government's control.
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Or I could see why it would be burdensome

2

and create different -- it would sort of go against the

3

sort of grain of really having an internal controls,

4

integrity management, getting away from this sort of

5

checklist mentality and really doing risk analysis

6

that's tailored to the pipeline, the particular risks.

7

And most integrity compliance in my experience are sort

8

of company-wide because you do want to have some control

9

by the folks who are qualified and who are responsible

10
11

for making those decisions.
THE HEARING OFFICER:

Okay.

Thank you.

12

Before we wrap up, does anyone have anything else that

13

they'd like to say?

14

how this case is going to proceed.

15

Otherwise, I'll just sort of cover

MR. HOGFOSS:

Just to give a very brief, I

16

guess, concluding statement on behalf of ExxonMobil,

17

really as we discussed, the essence of the entire NOPV

18

is that -- as stated in Item 1, is that the Company

19

failed to consider the risk of seam susceptibility of

20

ERW pipe, and we believe that the record, including the

21

materials submitted by the Agency, shows quite the

22

opposite, that the Company fully considered this risk

23

thoroughly over many years and using many different

24

methods and tools.

25

It's just that we didn't conclude that the
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risk existed, and that seems to be the nub of the

2

concern.

3

that the Agency conducted a very in-depth audit in 2007

4

of this precise pipeline of four inspectors for a full

5

week.

6

pipe was the same.

7

So, it does seem to be an issue of hindsight

8

post-incident.

And we do find that in contrast to the fact

Clearly they looked at this same conclusion.

The

The processes were the same then.

And we, again, encourage the Agency to

9
10

look not just at what they allege the Company did wrong

11

then but also what they did right, that they did try

12

many different ways.

13

and walk away and say, we don't have to worry about ERW

14

pipe.

15

the actual running of the crack tool; and the regs don't

16

tell you which one to use.

17

unfortunately did not find this defect.

They didn't make that conclusion

Instead, they took a lot of actions, including

They used a TFI tool that

And the next point is that two of the

18
19

nations leading experts in both ERW pipe threat

20

identification and pipeline risk management generally,

21

John Kiefner, Kent Muhlbauer, agree with that

22

conclusion.

23

developing the IMP program, on developing specifically

24

the analysis used to look at ERW pipe threat.

25

They worked with the company years ago on

And they agreed both before the fact and
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after the fact of this incident that this was one that

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you could not anticipate the probability of, and you

3

could not detect with the current technology.

4

course we mentioned that that also agrees with the

5

Agency's own most recent statements on this entire ERW

6

issue, that the report recently issued post-incident by

7

the Battelle and DNV and Kiefner groups on ERW conclude

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even after the fact of this incident, after the

9

allegations of this NOPV, that we're not there yet as an

And of

10

industry, as an Agency where we can reliably

11

identify ERW -- all ERW defects or have management

12

processes, including risk assessment models, that can do

13

that.
So, the bottom line is that's where we are

14
15

as a nation right now.

16

should be penalized for doing its best to work with the

17

leading experts to pursue the issues even when they

18

conclude they're not legally required and now after the

19

fact to be taking a hard look of what can they do

20

further.

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Agency's commissioned Battelle report recommends, saying

22

work together, force technology.

23

with some new models.

24

do.

25

And we don't think this company

And in fact, that's what the Battelle -- the

Let's try and come up

And that's what we're trying to

MR. WHITE:

I just have a brief concluding

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remark as well.

You know, we agree that the integrity

2

management regulations, you know, they are

3

performance-based regulations and do allow for some

4

flexibility.

5

flexibility and things within the operator's discretion.

6

And each pipeline system is different, and we do want --

7

operators are -- it's designed for operators to do

8

analysis and to -- in their decision-making processes.

They're intended to allow for some

But the regulations do have some -- I

9
10

think it goes sort of too far to suggest that there's --

11

you know, whatever decision the operator makes, that

12

they're all equal.

13

level of standard there that says, here are some factors

14

that have to be analyzed.

15

analyze one of those factors, that -- you know, the

16

Agency has to take the position that these regulations,

17

despite the fact that they're performance-based, that

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they are enforceable.

I mean, the regulations do have a

And if an operator does not

And so, our position is that not every

19
20

accident results in a enforcement case, which we said

21

earlier.

22

done in this case by experienced and qualified

23

investigators who put in dozens and hundreds of hours of

24

pages of documents and materials.

25

don't -- we don't make -- we don't issue NOPV letters

But, you know, a serious investigation was

And, you know, we

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lightly.

So, it becomes -- nothing -- at least speaking

2

for myself, nothing that I've heard today convinces me

3

that we should just withdraw this entire NOPV.

4

that based on the requirements and code and the evidence

5

in the record, I believe they have established

6

allegations.
THE HEARING OFFICER:

7

Thank you.

I think

Let's

8

talk about timing for any post-hearing submissions.

9

that something you'd like to take advantage of,

10

Is

submitting a post-hearing brief?
MR. HOGFOSS:

11

Yes, we would.

And I just

12

looked at the calendar and typically we look at 30 days

13

out and that falls right on 4th of July.

14

it to five weeks from today?

15

Johnny?

16

Catherine's furrowing her brow.

Would that be okay,

That would be changing it to July 9th.

17

MS. LITTLE:

18

THE HEARING OFFICER:

19

I am.

MR. HOGFOSS:

Probably looking at the

wrong month.

22

THE HEARING OFFICER:

23

MS. LITTLE:

24
25

I was factoring a

month from today would be Friday, July 11th.

20
21

Could we push

I think we might need a

little more time than that.
MS. JONES:

Is that doable?

45 days?

Yeah, might need a little more

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time.
MS. LITTLE:

2
3

THE HEARING OFFICER:

July 25th.

Is that

about right, I think?

6

MS. LITTLE:

7

MS. JONES:

8

THE HEARING OFFICER:

9

What would that put

us to?

4
5

45 days.

Does that sound okay?
That's better.
I think that's six

weeks from today.

10

MR. SEELEY:

11

Mr. Counselor over there.

Birthday present for

12

MR. RANDOLPH:

Thank you.

13

THE HEARING OFFICER:

14

Okay.

July 25th?

Okay.

I'll just recap some of the things

15

I stated earlier.

16

is submitted to me, I'll be preparing a recommended

17

decision which is forwarded to the Associate

18

Administrator for Pipeline Safety who will issue the

19

final order.

20

regulations, the Regional Director will be submitted a

21

recommendation to me, which I am not bound by.

22

After any of the additional material

In accordance with our procedural

I'll give full consideration to all

23

evidence and arguments that were presented here today

24

and the written materials when I prepare my independent

25

recommendation for final action.
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When the final award is issued, our

2

regulations permit the Respondent to petition for

3

reconsideration of the final order within 20 days of

4

receipt.

That's in Section 192.43.
Any additional questions about anything

5
6

before we adjourn?

7

adjourned.

8

today.

9

No?

Okay.

Well, we'll stand

Thank you-all for your participation

(Hearing adjourned at 12:19 p.m.)

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* * * * *

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2

BEFORE THE
U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY

3

IN THE MATTER OF
4
5
6

)
)
EXXONMOBIL PIPELINE COMPANY )
PEGASUS PIPELINE INCIDENT
)
(MARCH 29, 2013)
)
MAYFLOWER, ARKANSAS
)

CPF NO. 4-2013-5027
NOTICE OF PROBABLE
VIOLATION

7
8

REPORTER'S CERTIFICATE

9
10

PHMSA HEARING

11

June 11, 2014

12
13
14

I, Roxanne K. Smith, the undersigned Certified

15

Shorthand Reporter in and for the State of Texas,

16

certify that the facts stated in the foregoing pages are

17

true and correct.

18

I further certify that I am neither attorney or

19

counsel for, related to, nor employed by any parties to

20

the action in which this testimony is taken and,

21

further, that I am not a relative or employee of any

22

counsel employed by the parties hereto or financially

23

interested in the action.

24
25
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Subscribed and sworn to under my hand and seal
of office on this the 18th day of July, 2014.

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4
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_______________________________
Roxanne K. Smith, CSR
Texas CSR 6290
Expiration: 12/31/2012
Firm Registration No. 62
1225 North Loop West, Suite 327
Houston, Texas 77008
(713) 626-2629

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Prepared for Release in PHMSA FOIA
2014-0164_000561

  

Before the

US. Department of Transportation
Pipeline and Hazardous Materials Safety Administration

 

Of?ce of Pipeline Safety

In the Matter of 
. 
EXxonMobil Pipeline Company CPF No. 4?2013-5027
Pegasus Pipe Line incident Notice of Probable Violation
(March 29, 2013), May?ower, Arkansas -)


 

Index of Attached Exhibits

 

No.

Exhibit

 

Af?davit ofJohn Kiefner (5/22/14)

 

Af?davit of Kent Muhlbauer (5/3 1/14)

 

M. Baker, Low Frequency ERW and Lap Welded Longitudinal Seam Evaluation, Chapter 4 
Figure 4.1 (April 2004)

 

IMP Manual Excerpts, Sections 44, 51(4), 5.4 (2012)

 

OIMS Framework, Elements 2.4; 7.2 (2009)

 

OIMS System 2A, Attachment #l Risk Matrix Methodology (rev?d 2004)

 

EMPCO TIARA Manual, Section 8.0 (2007)

 

Memo-regarding Corsicana to Patoka LSFSA 02/10/04)

 

Memo regarding Corsicana to Patoka LSFSA (2/10/05)

 

Management of Change Form No. 05-2829 (8/l0/05)

 

EM Management of Change Form No. 05-2833 (8/10/05)

 

EMPCO Hurst Metallurgical Analysis of Hydrotest Failures Excerpt Report No. 51708 (6/21/06)

 

TIARA Foreman to Conway UDT (6/26/06)

 

 

Corsicana to Patoka Summary of Hydrotest Learnings (7/06/06)

 

Hurst Metallurgical Analysis of Hydrotest Failures Excerpt Report No. 51763 (7/06/06)

 

EM Integrity Assessment Data Form 32 Foreman to Conway (7/26/06)

 

 

 

 

EM TIARA Foreman to Conway Manufacturing Threat Classi?cation (7/26/06)

 

Prepared for Release in PHMSA FOIA
2014-0164_000562

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

t1 8 EMPCO TIARA Foreman to Conway Risk Assessment Summary (7/27/06)

19 EM PCo?Risk Assessment Summaries: Corsicana to Foreman, Conway to Doniphan, Doniphan to
Patoka (2006/2007)

20 1MP Preventive Mitigative Actions Form 6.1, Foreman to Conway (2007)

'2 1' Foreman to Conway LSFSA and Pipelife Analysis Excerpts (2007)

4 22 Patoka to Corsicana LFSA Review (2009)

23 Email from NDT (8/23/10)

24 NDT Preliminary 1L1 Report Conway to Corsicana (received 8/23/10)

25 Repair Form MP 164.05 (8/28/10)

26 1MP Exception Form 1.2 (12/17/10)

27 Final NDT 1L1 Report Repair Summary Conway to Corsicana Excerpts (201 l)

28 TIARA UDT Conway to Corsicana(20  1)

29 Conway to Corsicana LSFSA. and Pipelife Excerpts (201 1)

30- Email from NDT MP 142.39 Dig Sheet (1/10/1 1)

31 Repair Form MP 142.39 (1/12/1 1)

32 Repair Form PL-0751 MP 

33 1MP Exception Form 

34 Conway to Corsicana Manufacturing Threat Classi?cation and Risk Assessment
Summary (3/1 1)

35 Conway to Coriscana 1MP Form 3.2 IAD Form (3/15/1 1)

36 EM Conway to Corsicana Form 6.1 (7/21/1 1)

37 Conway to Corsicana EFRD Form 6.2 (7/21/1 1)

38 1MP Exception Form 1.2 (8/02/13)

39 Exception Form 1.2 (8/28/i3)

 

 

Prepared for Release in PHMSA FOIA
2014-0164_000563

 

 

Index of Exhibits Included by Reference Only

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

No. Exhibit

40 Patoka to Corsicana 2005/2006 Hydrostatic Test Reports (MP 127-437)

41 Metallurgical Analysis performed by Hurst Report No. (12/19/05)

42 EM LSFSA Foreman to Conway and Pipelife Analysis (2006)

43 EM Metallurgical Analysis performed by Hurst Report No. 41305 (4/20/06)

44 Metallurgical Analysis performed by Hurst, Report No. 41500 (4/24/06)

45 EM Metallurgical Analysis performed by Hurst Report No. 51695 (6/17/06)

46 Metallurgical Analysis performed by Hurst Report No. 51708 (6/21/06)

47 Metallurgical Analysis performed by Hurst Report No. 51763 (7/6/06)

48 Foreman to Conway Risk Assessment (7/27/06)

49 EM Manual (2007)

50 Conway to Corsicana NDT MFL Combo 1L1 Final Report (2010)

51 EMPCO Patoka to Conway GE TF1 Final Report (2010)

52 EM LSFSA Conway to Corsicana and Pipelife Analysis (201 1)

53 EMPCO 1MP Manual (2012)

54 EMPCO Conway to Corsicana GE TFI Final Report (2013)

SS Hurst Metallurgical Investigation of Pegasus Pipeline Report No. 64961 MP 314 (7/9/13)
56 Pegasus Root Cause Failure Analysis Final Report Appendices (Mar. 26, 2014)

 

 

 

Prepared for Release in PHMSA FOIA
2014-0164_000564

 

ExxonMobil Pipeline Company
Notice of Probable Violation No. CPF 4-2013-5027
June 11, 2014 Hearing Transcript: EMPCo Proposed Transcript Errata
Page

Line(s)

Correction

5

14

Capitalize “Office of Chief Counsel”

7

24-25

Capitalize “Associate Administrator for Pipeline Safety”

8

6

Capitalize “Regional Director”

8

16

Change “192.43” to “190.243”

12

11

Change “operate” to “cooperate”

13

10

Change “to – where appropriate” to “to, where appropriate,”

13

18

Change “Agency” to “Company”

14

9

Change “prepared” to “repaired”

14

12

Change first “report” to “reported”

14

17

Change to “Exhibits”

14

18

Change first “well” to “wall”

16

2

Change “by” to “from”

20

6

Change “fuel” to “tool”

20

7

Change “in” to “and”

20

14

Delete “,” following rule

20

17

Insert “as to” following 2001

20

23

Insert “it” following but

24

8

Changes “sides” to “sites”

32

3

Change “drying” to “drawing”

34

15

Changed “request” to “requested”

37

13

Change “got” to “sent”

37

17

Add “just” between “not __ with”

38

2

Change “get” to “meet”

42

14

Change “track” to “trap”

Prepared for Release in PHMSA FOIA
2014-0164_000565

 CPF No. 4-2013-5006
May 2, 2013 Hearing
EMPCo Proposed Transcript Errata
Page

Line(s)

Correction

44

1

Change “selected” to “selective”

44

3

Change “lead in delay” to “be delayed”

45

20

Change “track” to “trap”

49

6

Change “Is that” to “It is that”

49

10

Change “thread” to “threat”

50

23

Change “and” to “in”

54

12

No apostrophe in “questions”

56

22

Delete “the”

60

1

Change “time” to “threat”

63

6

Delete “include”

63

22

Change “not” to “but”

64

8

Add “was” between “Company ___ doing”

64

17

Add “to” before “Lake Maumelle”

69

13

Change “merge of our” to “merger of”

69

17

Change “merges” to “mergers”

71

15

Insert a quotation mark before “As”

71

18

Insert a quotation mark following “segments”

71

19

Insert a quotation mark before “”(such”

71

22

Insert a quotation mark following “segment.”

72

23

Add “and” between “corrosion” and “caliber”

72

23

Change “caliber” to “caliper”

75

20

Change “and” to “of”

75

21

No apostrophe in “changes”

78

23

Change “backward” to “back towards”

78

21

Change “clarifications” to “clarification”

80

20

Add “the” between “read ____ NOPV”

81

10

Change “incident” to “incidence”
2
Prepared for Release in PHMSA FOIA
2014-0164_000566

 CPF No. 4-2013-5006
May 2, 2013 Hearing
EMPCo Proposed Transcript Errata
Page

Line(s)

Correction

81

11-12

“call before you dig” should be in quotes

81

25

Change “370” to “pre-70”

82

15

Change “all the” to “oil”

82

15

Change “its” to “US”

83

20

Change “verbiage” to “verbage”

84

13

Change “if” to “is that”

84

14

Change “pipeline” to “pipeline,”

86

4

Change “regulars” to “regulations”

86

5

Change “response” to “responds”

87

10

Change “metallurgists of” to “metallurgist”

89

12

Delete “is” following well

90

6

Insert a quotation mark before “that”

90

7

Change “unique, that” to “unique, and that”

90

10

Insert a quotation mark following “industry.”

92

12

Change “affidavits talk” to “affidavits -- talk”

92

17

Add “program” after “Pipelife”

93

15-16

Insert a quotation mark before “Hydrostatic” and following “failure.”

94

16

Change “segment” to “statement”

96

11

Insert a quotation mark before “I”

96

18

Insert a quotation mark following “2013.”

97

3

Change “line’s” to “line is”

97

15

Delete the second “was” between “failure” and “susceptible”

98

11

Insert a quotation mark before “If” and change “end” to “in”

98

13

Insert a quotation mark following “susceptible.”

100

24

Change “says failures” to “says, “Failures”

101

1

Insert a quotation mark following “fatigue.” and change “continues, if”
to “continues, “If”
3
Prepared for Release in PHMSA FOIA
2014-0164_000567

 CPF No. 4-2013-5006
May 2, 2013 Hearing
EMPCo Proposed Transcript Errata
Page

Line(s)

Correction

101

5

Insert a quotation mark following “requirements.”

103

17

Insert a quotation mark before “All”

103

20

Insert a quotation mark following “otherwise.”

103

22

Change “it” to “I”

105

12

Change “slime” to “line”

108

24

Change “seeking” to “secant”

117

14

Change “is is” to “is in”

117

18

Change “inspect to “inspected” and change “look” to “looked”

125

8

Change “huge.” to “huge pressures.”

130

21

Change “and” to “an”

131

8

Change “be the” to “be in the”

131

16

Change “pump” to “IMP”

132

4

Change “go” to “do”

132

10

Change “relate” to “relates”

135

1

Change “then” to “them”

136

8

Change “he” to “we”

137

17

Insert a quotation mark before “An”

137

24

Insert a quotation mark following “anomalies.”

139

16

Change “determine” to “determined”

140

4

Insert a quotation mark before “The”

140

7

Insert a quotation mark following “goals.”

140

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Change “tells” to “does”

140

10

Insert a quotation mark before “The”

140

12

Insert a quotation mark following “system.”

142

25

Change “score” to “scores”

143

10

Add “failure” between “seam” and “susceptible”

143

18

Change “pro model” to “per mile”
4
Prepared for Release in PHMSA FOIA
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 CPF No. 4-2013-5006
May 2, 2013 Hearing
EMPCo Proposed Transcript Errata
Page

Line(s)

Correction

143

21

Add “leaks” after “girth welds”

146

22

Delete second “in” and change “Pipes” to “PIPES”

146

23

Change “regulatory” to “regulations,”

146

24

Insert a quotation mark before “related”

146

25

Insert a quotation mark following “violations,”

147

1

Change “Carey” to “Kerry”

147

14

Insert a quotation mark before “are so”

147

15

Insert a quotation mark following “violation.”

148

2

Change “aren’t” to “are”

148

5

Change “laws” to “law”

151

7

Capitalize “Associate Administrator”

154

14

Change “370” to “pre-70”

154

14

Change “models” to “miles”

155

8

Add “to” between “response” and “that”

158

19

Change “comes” to “come”

161

4

Change “DMV” to “DNV”

163

13

Change “curling” to “furrowing”

164

11-18

Capitalize “Associate Administrator for Pipeline Safety” and “Regional
Director”

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Prepared for Release in PHMSA FOIA
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 ExxonMobil Pipeline Company
Notice of Probable Violation No. CPF 4-2013-5027
June 11, 2014 Hearing Transcript: PHMSA’s Corrections
Page

Line(s)

Correction

8

4

Change “we’ll” to “will”

11

25

Add “an” prior to “immediate”

14

6

Change “inform” to “confirm”

14

9

Change “prepared” to “repaired”

14

12

Change “report” to “reported”

14

14

Change “tool line” to “tool run”

14

18

Change “well” to “wall”

17

4

Change “action anomaly” to “action taken on the anomaly”

18

3

Change “on” to “of”

18

9

Change “pressure” to “ratio”

23

8

Change “immediately” to “immediate”

23

12-13

Change “to mediate that is” to “for immediates is that”

26

24

27

2

Insert quotation mark after “Page 2,” before “here” and capitalize
“Here” (begin quote)
Insert quotation mark after the word “him.” (end quote)

28

14

30

9

Please confirm with Ms. Jones that “immediate repair” should in fact
be replaced with “safety related condition.” I believe that was her
analogy as she continues the comparison in line 18.
Change “immediates” to “immediately”

39

12

Insert quotation mark (start quote) before “our”

39

15

Insert quotation mark (end quote) after “days.”

40

5

Add “the” before “careful evaluation”

40

9

Add “on” after “goes”

40

12

Change “create” with “can impact”

41

3

Change “traps” to “trap”

41

11

Add “which” before “doesn’t”

Prepared for Release in PHMSA FOIA
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 ExxonMobil Pipeline Company
Notice of Probable Violation No. CPF 4-2013-5027
June 11, 2014 Hearing Transcript: Suggested Corrections
Page

Line(s)

Correction

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5

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42

14

Change “track” to “trap”

43

3

Change “receive” to “received”

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5

Change “track” to “trap”

45

20

Change “track” to “trap”

46

9

Change “point on it” to “pointed it out”

47

11

Change “someone from” to “performing”

49

10

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49

24

Change “that it’s to perform” to “that is to be performed”

51

8

Insert “of” after “cases”

51

9

52

9

Change “yes or no to that answer, there were” to “yes or no, been no
for that answer then there were”
Change “made and” to “made in”

55

15

Change “and” to “TIARA,”

55

16

Change “TIARA has” to “there is”

56

6

Add “it” before “in”

56

16

Change “not” to “no”

56

18

Change “known” to “no identified”

57

8

Change “seam” to “same”

57

14

Insert quotation mark (start quote) before “Go”

57

16

57

16

Insert quotation mark (end quote) after forward.” And remove comma
at end of line 16
Change “represented in” to “representative of”

57

17

57

17

57

17

57

17

Insert “. . .” after “probability” (to indicate that not all of the quote was
read)
Change “at” to “a”

57

19

Insert end quotation mark after “away.”

Change “well” to “With” and insert a quotation (start quote) in front of
“With” and remove comma that was after “well”
Remove period after yes and make “It” “it”

2
Prepared for Release in PHMSA FOIA
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 ExxonMobil Pipeline Company
Notice of Probable Violation No. CPF 4-2013-5027
June 11, 2014 Hearing Transcript: Suggested Corrections
Page

Line(s)

Correction

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1

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60

20

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64

8

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66

23

Delete “in”

66

25

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71

18

Change “threat” to “threats” and “immediate” to “intermediate”

72

8

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72

23

Change “caliber” to “caliper”

80

7

Delete “our”

84

14

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84

19

Change “what” to “that”

89

17

Change “force” to “enhance”

90

3

Insert “root” in front of “cause”

90

4

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93

21

Change “exists. If” to “exists if”

93

22

Insert “limits” before “stress”

93

23

Insert “to” before “prevent”

101

10

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101

25

Insert “properties.” at the end of the line

102

10

Change “may be” to “may have”

102

24

Change “that is we see” to “that we see”

108

24

Change “log-seeking” to “log-secant”

110

15

Change “word” to “work”

111

10

Add “appear” after failures”

111

11

Change “or” to “of”

112

9

Change “That’s” to “It’s”

112

17

Change “fatigued” to “fatigue”
3
Prepared for Release in PHMSA FOIA
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 ExxonMobil Pipeline Company
Notice of Probable Violation No. CPF 4-2013-5027
June 11, 2014 Hearing Transcript: Suggested Corrections
Page

Line(s)

Correction

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19

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115

11

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122

18

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126

10

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132

4

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132

6

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135

1

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135

3

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142

12

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154

14

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155

2

Insert “accidents” before “that”

4
Prepared for Release in PHMSA FOIA
2014-0164_000573

 Before the
U.S. Department of Transportation
Pipeline and Hazardous Materials Safety Administration
Office of Pipeline Safety

In the Matter of
ExxonMobil Pipeline Company
Pegasus Pipeline incident
(March 29, 2013), Mayflower, Arkansas

)
)
)
)
)
)
)

CPF No. 4-2013-5027
Notice of Probable Violation

RESPONDENT’S
POST HEARING BRIEF

Prepared for Release in PHMSA FOIA
2014-0164_000574

 INTRODUCTION
As drafted, the Notice of Probable Violation (NOPV) issued to ExxonMobil Pipeline Company
(Respondent or Company) implies that violations must have occurred because there was an
incident. The Pipeline Safety Act (PSA) has no strict liability provision, however, a fact that was
admitted by the Pipeline and Hazardous Materials Administration (PHMSA or Agency) at the
Hearing. The Agency must therefore prove alleged violations, not presume them. The Agency
has not established that proof in this case.
I.

The Law Applicable to LF-ERW Pipe

In order to fully evaluate the allegations made by PHMSA in this matter, particularly for NOPV
Items 1-4 and 7, it is necessary to understand the state of the law underlying integrity
management regulation of low frequency electric resistance welded (LF-ERW) pipe. The
National Transportation Safety Board (NTSB), PHMSA and leading experts in pipeline
metallurgy and risk management nationally have not yet been able to develop a standard process
that allows operators to identify all features associated with the risk of seam failure on LF-ERW
pipe, because current technology does not provide adequate data to identify all ERW anomalies.
The NOPV in this matter, however, flatly asserts that Respondent had “more than adequate
information” to be able to do just that. NOPV Item 1, p. 2. That assertion is simply wrong. The
Agency itself has not been able to produce rules or guidance that would direct operators to find
such isolated anomalies, and the leading experts in this area – both Respondent’s and the
government’s – have concluded that technology is not yet capable of finding all these anomalies.
Various methods have been used over the decades to manufacture steel pipe used in construction
of oil and gas pipelines. One of the methods used prior to 1970 involved joining the long seam
of pipe segments by LF-ERW. In 1986, two long seam failures of pre-1970 LF-ERW pipe
occurred in Minnesota, leading the Office of Pipeline Safety (OPS) to issue alerts to industry in
both 1988 and 1989. Exhibit 72, OPS Alert ALN-88-01 (Jan. 28, 1988); Exhibit 73, OPS Alert
ALN-89-01 (Mar. 8, 1989). The alerts simply warned that LF-ERW welds had the potential to
fail in limited circumstances, and that operators should consider that potential risk while
conducting pipe inspection and maintenance activities.
In 1994, and again in 2000 (in the integrity management program (IMP) rule), OPS issued rules
directing liquid pipeline operators to conduct hydrostatic pressure testing of pre-1970 LF-ERW
pipe in certain circumstances. Exhibit 74, Final Rule, 59 Fed. Reg. 29379 (June 7, 1994);
Exhibit 75, Final Rule, 65 Fed. Reg. 75378 (Dec. 1, 2000). The Agency also commissioned a
study resulting in a report issued in 2004, proposing a protocol for operators to use in evaluating
the risk posed by pre-1970 LF-ERW pipe. Hearing Exhibit No. 3 (Baker-Kiefner Report). The
protocol it proposed was not incorporated into OPS rules, but operators were encouraged to
follow it. Respondent not only followed that protocol, it retained one of the study co-authors
(John Kiefner) to help adapt the protocol specifically to the Company’s IMP.
The OPS rules regarding pre-1970 LF-ERW pipe for liquid lines are minimal, and more advisory
than prescriptive. In fact, there are only three places in the entirety of Part 195 that address pre1970 LF-ERW pipe: 49 C.F.R. Part 195.303(d) (which was a one-time opportunity to conduct
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 risk based alternatives to hydrotesting); and Parts 195.452(e)(1)(ii) (requiring consideration of
manufacturing information as a risk factor in IMP threat identification) and 195.452(j)(5)
(requiring assessment methods for LF-ERW pipe susceptible to seam failure to be capable of
assessing seam integrity, among other things). Where a segment is found to be susceptible to
longitudinal seam failure under the IMP rules, an operator is directed to use certain integrity
assessment tools. Other than the requirement to “consider” the risk of ERW seam failure,
however, the Agency has offered no specific guidance to operators beyond the non-mandatory
2004 Baker-Kiefner report.
In 2007, a pipeline accident in Carmichael, Mississippi involving LF-ERW pipe led the NTSB to
issue two formal recommendations to OPS (by then part of PHMSA). Recommendation P-09-01
urged PHMSA to “conduct a comprehensive study to identify actions that can be implemented
by pipeline operators to eliminate catastrophic longitudinal seam failures in electric resistance
welded (ERW) pipe.” Exhibit 68, NTSB Accident Report, NTSB/PAR-09/01, at p. 51 (Nov. 1,
2007). Recommendation P-09-02 encouraged PHMSA to “implement actions needed [based on
the results of the study requested in P-09-01].” Id. NTSB stated that its reason for making such
recommendations was a conclusion that “[PHMSA’s] current inspection and testing programs
are not sufficiently reliable to identify features associated with longitudinal seam failures of
ERW pipe prior to catastrophic failure” of an operating pipeline. Exhibit 69, Letter from NTSB
to PHMSA, at p. 3 (Oct. 27, 2009), transmitting recommendations (emphasis added).
NTSB’s recommendations to PHMSA regarding LF-ERW pipe went unaddressed for several
years. The NTSB issued letters to the Agency in 2010, 2011 and 2012, inquiring about the status
of PHMSA’s response on the issue. In the 2010 letter from NTSB Chair Deborah Hersmann to
PHMSA Administrator Cynthia Quarterman, NTSB stated that it was “disappointed” that
PHMSA had not yet commenced a study on LF-ERW pipe. Exhibit 70, Letter from NTSB to
PHMSA, at p. 1 (Dec. 29, 2010). In a subsequent letter, NTSB noted that it understood the
Agency finally had commissioned the ERW study, which was expected to be completed by the
Battelle Memorial Institute by November 2012. Exhibit 71, Letter from NTSB to PHMSA, at p. 2
(Oct. 19, 2011).
It was not until five years after the NTSB issued Recommendations P-09-01 and P-09-01 to
PHMSA about LF-ERW pipe that Battelle issued an interim report.” Exhibit 65, Battelle
Institute, “Final Interim Report” on ERW Seam Failures (Sept. 20, 2012) (Battelle Interim
Report). A little more than a year after that, Battelle issued a “Final Summary Report,” dated
October 23, 2013. Significantly, this “Final Summary” report was issued after the Mayflower
incident. The October 2013 report commissioned by PHMSA noted that:
…it is clear that gaps remain both in the understanding of the [ERW] failure process, and
in quantifying the effectiveness of current schemes and technology to manage the ERW
pipeline network. As such, the work initiated under [this study project] is being
continued to bridge those gaps.
Exhibit 66, Battelle Final Summary Report on ERW Seam Failures, p. vi (Oct. 23, 2013)
(Battelle Final Summary Report).

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 The Battelle study commissioned by PHMSA is still ongoing, long after NTSB issued its
Recommendations on point, and long after the Mayflower incident that is the subject of this
NOPV. On May 31, 2014, Battelle issued its “12th Quarterly Report” on the continuing work on
this issue. That update notes that 15 Task Reports have been issued under Phase I of the project,
but that the stated goal of the study has not yet been met: “to identify the factors the pipeline
operators must consider in order to assure that their ERW pipelines are safe.” Exhibit 67,
Battelle ERW Study, 12th Quarterly Report, p. 1, “Public Page” (May 31, 2014).
Battelle’s reports note that the frequency of occurrence of long seam weld failures on LF-ERW
pipe has been declining since the 1960s. Exhibit 65, Battelle Interim Report p. 76 (Sept. 20,
2012). That trend is obviously important, as more than 25% of all liquid pipelines in the U.S.
contain pre-1970 ERW pipe. PHMSA, Hazardous Liquid Annual Data 2012 (as of May 1, 2014)
available at www.phmsa.dot.gov (includes direct current welded pipe). If the risk of seam failure
was greater than it is, PHMSA could direct more mandatory inspection or testing activities than
it has. To the credit of NTSB and PHMSA, however, study of this risk continues, with a goal of
providing pipeline operators with better tools and methods to predict and identify LF-ERW long
seam anomalies that could otherwise lead to failure in limited circumstances.
As discussed below, Respondent complied with all applicable law and guidance in evaluating the
Pegasus Pipeline for susceptibility to long seam failure of LF-ERW pipe. Post-incident analysis
confirmed that the anomaly was not capable of reliable detection. In sum, more than five years
of vigorous study and analysis by PHMSA to develop actions that could be implemented by
pipeline operators to eliminate LF-ERW failures has offered no definitive results or guidance, yet
PHMSA’s NOPV directly faults Respondent for not completely eliminating the possibility of a
LF-ERW seam failure on a pipeline that operated for over 60 years without incident. The
Battelle study on ERW issues, commissioned by PHMSA, continues, but its preliminary findings
support the Company’s position in this proceeding.
II.

Respondent Complied with the Law Applicable to LF-ERW Pipe with an IMP Plan,
Engineering Analyses on Seam Risk, ILIs and Hydrotests (NOPV Items 1-4, 7)
A.

Overview of Relevant NOPV Allegations

In NOPV Items 1 – 4 and 7, PHMSA asserts five violations of its IMP regulations
concerning LF-ERW pipe. PHMSA specifically alleges that Respondent failed to (1) consider
the susceptibility of pre-1970 LF-ERW pipe seam failure as a risk factor when establishing its
assessment schedule, citing 49 C.F.R. Part 195.452(e)(1) (NOPV Item 1); (2) establish a five year
reassessment interval, citing Part 195.452(j)(3) (NOPV Item 2); (3) obtain a variance from the
five year interval to extend the seam/crack tool assessment of Conway to Corsicana in violation
of its procedures (IMP Plan 5.1), citing Part 195.452(b)(5), (j)(4) and (i) (NOPV Item 3); (4)
prioritize higher risk segments of the Pegasus Pipeline for reassessment, citing 195.452(e) and
(j)(3) (NOPV Item 4); and (5) follow internal procedures (IMP Plan 5.4 and OIMS 2.4) by not
updating its risk assessment when the TFI tool run was delayed, citing 49 C.F.R. Part
195.452(b)(5) and (j)(1) and (2) (NOPV Item 7).
All of these allegations hinge on PHMSA’s presumption, conveniently made after the
fact, that the Pegasus Pipeline should have been determined to be susceptible to seam failure.
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 All of these allegations, however, are unsupported by the facts, the law and available guidance.
The allegations and their underlying presumption also conflict with the opinions of the nation’s
leading experts on these issues.
B.

Respondent Appropriately Conducted Seam Susceptibility Analyses and
Pressure Testing of LF-ERW Pipe

As discussed in Section I, above, other than alerting operators to the potential risk of
seam failure on some LF-ERW pipe, PHMSA has provided little regulation or guidance on how
to anticipate or locate LF-ERW anomalies. The most recent research into these issues was
commissioned by PHMSA and conducted by Battelle, which concluded (notably, after the
Mayflower incident) that technology and methods are not yet well enough developed to be able
to identify all LF-ERW anomalies, even as the occurrence of LF-ERW related incidents is
declining. The record in this case shows that Respondent did far more than required by existing
rules or guidance to identify LF-ERW pipe that is susceptible to seam failure.
Respondent incorporated LF-ERW consideration procedures into its IMP program from
the very outset, using the services of one of the co-authors PHMSA retained to develop guidance
on the topic. The Company carefully considered all relevant risk factors, based on all available
information, in establishing its baseline and reassessment schedules. Respondent subsequently
completed four separate engineering analyses specific to the Pegasus Pipeline, looking at the risk
of seam failure and incorporating information from three hydrostatic pressure tests and three inline inspection (ILI) runs (one with a crack/seam tool).
John Kiefner, who co-authored the 2004 LF-ERW seam failure risk study commissioned
by PHMSA, and who was part of the 2012/2013 Battelle study commissioned by PHMSA to
further examine ERW risk, has submitted an affidavit for this matter. As stated clearly in his
affidavit, hydrostatic test failures alone are not indicative of susceptibility to seam failure.
Hearing Exhibit No. 1, Kiefner Aff. ¶ 13. There must be evidence of fatigue-related failures,
selective seam corrosion or other time dependent defects (such as stress corrosion cracking). Id.
Kiefner goes on to describe his review of the data associated with the Mayflower incident, noting
that the “point of failure showed no evidence of fatigue.” Id. at ¶ 17. More significantly,
Kiefner concludes that
[he has] reviewed the integrity data that would have been available to EMPCo prior the
incident regarding the Conway to Corsicana testable segment. Based upon that review,
EMPCo’s conclusion that the segment was not seam-failure-susceptible under the federal
regulations was reasonable, and was consistent with the seam failure susceptibility
determination guidance available prior to March 29, 2013.
Id. at ¶ 19. Kent Muhlbauer, a national pipeline risk management expert who has also worked
with PHMSA, also submitted an affidavit stating that
It is my opinion that the Company properly recognized the issues associated with LFERW pipe, reacted to the threats on the Pegasus Pipeline, and complied with the Part 195
IMP regulations.
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 Hearing Exhibit No. 2, Muhlbauer Aff. at ¶ 11.
At the Hearing, PHMSA raised additional issues concerning Respondent’s methods and
analyses used to evaluate seam risk, suggesting that the Company did not sufficiently consider
that the pipe was brittle, and therefore the continued focus on fatigue analysis was misplaced.
PHMSA asserted that Respondent should have focused on the hardness and toughness of the pipe
in its analyses. Transcript of Hearing on PHMSA NOPV CPF 4-2013-5027 (Jun. 11, 2014)
(Transcript), p. 111, lines 1-9.
The Company’s detailed seam susceptibility and fatigue analyses expressly considered all
available information regarding the Pegasus Pipeline, including its manufacturing history, the
pipe material properties (such as documented fracture toughness values), sixty years of operating
and maintenance history, leak history, and the results of prior pressure tests and integrity
assessments (and subsequent metallurgical analysis). In the absence of evidence of other failure
mechanisms on the Pegasus Pipeline, including pressure reversals, environmental cracking, and
hardness related to the seam, the Company relied on the Baker-Kiefner process which directs an
operator to analyze pressure cycle-induced fatigue.1 Indeed, the Company directly consulted
with John Kiefner, one of the world’s leading experts on LF-ERW seam failure analysis.
Contrary to PHMSA’s allegations at the Hearing, Respondent’s Pipelife fatigue analysis software
(developed by John Kiefner) specifically considers toughness (i.e., the measure of a pipe’s
brittleness) as a factor in the analysis, and the Company followed the manual’s instruction to use
actual representative toughness values when they are available.2
In addition, at the Hearing, PHMSA asserted that Respondent should have run its
hydrotests at higher pressures, from 90-100% SMYS, in order to properly assess seam risks or
threats. Transcript, p. 105, lines 8-15. The Agency’s regulations do not specify any such
pressures or hydrotest parameters for LF-ERW pipe beyond compliance with Subpart E,
however.3 To that very point, Kiefner noted in his affidavit that “the level of hydrostatic test
                                                            
1

As attested to by Kiefner, the Company’s conclusion that the segment was not seam failure susceptible was
“reasonable” and “consistent with available guidance,” further based on the examinations of the prior hydrostatic
test failures, there was “no evidence of excessively hard heat affected zones.” Hearing Exhibit No. 1, Kiefner Aff.
¶¶ 18, 19.

2

The 2011 analysis used a seam toughness CVN value of 7 because it was the average representative toughness
value documented by the Hurst 2006-2007 analyses of the 2005-2006 hydrotest failures. Further, Kiefner notes that
his review of the pipe material properties indicates that the anomaly that caused the Pegasus incident “was not
capable of reliable detection given that it exhibited atypical characteristics not frequently seen before in the
industry.” Hearing Exhibit No. 1, Kiefner Aff. ¶ 24.
3

This issue was raised at the Hearing and Respondent pointed out that there are no Agency regulations or guidance
that require a higher hydrostatic test pressure for this type of pipe. Transcript, p. 105, lines 17-18. While PHMSA
suggested that 49 C.F.R. Part 195.303(d) has bearing on this issue, as explained by Respondent at the Hearing – and
notably not challenged by PHMSA – that provision was enacted in 1998 and established a one-time historical
opportunity for operators to elect a risk-based alternative to pressure testing of pre-1970 pipe, and specifically at
subsection (d) for pre-1970 LF-ERW pipe. Transcript, p. 105, line 16 – p. 106, line 11. That provision was enacted
prior to the IMP rules, and other than specifying considerations for seam susceptibility analyses, it has no other
relevance. Id. Further, 195.303(d) required pressure testing of pre-1970 LF-ERW pipe that was susceptible to seam

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 pressure employed in 2006 on the Conway to Corsicana segment was consistent with the 49
C.F.R. Part 195 regulatory requirements.” Hearing Exhibit No. 1, Kiefner Aff. ¶ 22.
Even after its conclusion that the Pegasus Pipeline was not susceptible to seam failure,
and despite the lack of direction or guidance from the Agency, the Company continued to
conduct tests and analyses, using both company engineers and third parties, to reevaluate
whether the line was susceptible.4 No actionable anomaly was ever identified on the segment of
pipe that failed in the Mayflower incident. Significantly, even after the incident, metallurgical
examination revealed a pipe joint with highly unusual chemical and mechanical properties and
unique characteristics at the point of failure. Hearing Exhibit No. 1, Kiefner Aff. ¶¶ 16, 17.
There is no evidence that the anomaly that failed was capable of reliable detection by technology
and methods of inspection used at the time in compliance with applicable law.
The Agency conducted an intensive inspection of the Company’s IMP program and LFERW procedures in 2007, specifically with respect to the Pegasus Pipeline, and found no issue
with those procedures or their implementation. The record shows that Respondent complied with
all of PHMSA’s existing rules and guidance in trying to anticipate and identify LF-ERW seam
susceptibility issues on the Pegasus Pipeline. Hearing Exhibit No. 1, Kiefner Aff. ¶ 21 (“The
seam-integrity assessment activities that EMPCo employed on this segment of pipe were
consistent with the Baker Report Flow Chart and IMP regulations and guidance in effect at the
time.”).
C.

Respondent Complied with Applicable Law and Guidance in Conducting
ILI of the Pegasus Pipeline

Given all available information and analyses, conducted over a period of time,
Respondent concluded that the Pegasus Pipeline was not susceptible to seam failure. Despite
that conclusion, the Company elected to voluntarily run a seam/crack tool in 2012. The next
reassessment after the 2010 ILI on the Conway to Corsicana segment was not due until 2015, but
the Company voluntarily decided to employ the seam/crack tool well in advance of that date.  
Because a seam/crack tool was not required, it was not subject to the variance reporting
requirements under the IMP rules or the Company’s IMP procedures, as alleged in NOPV Item
3. The Company’s IMP Manual Section 5.1 incorporates verbatim the language of Part
195.452(j)(3), which requires an operator to request a variance when it cannot meet the 5 year
interval. The rules do not require an operator who voluntarily elects to reassess a line with a
seam tool, however, to request a variance.

                                                                                                                                                                                                
failure pursuant to pressure levels under Part 195 Subpart E pressure test which is consistent with the pressure test
that Respondent performed in 2006 on the Pegasus Pipeline.
4

Although not directly relevant to the allegations set forth in the NOPV, at the Hearing and in the Agency’s Pipeline
Safety Violation Report (PSVR), PHMSA suggests that the Company has not updated its LF-ERW susceptibility
analysis in light of a 2012 incident in Torbert, Louisiana or participated in industry research regarding these issues.
These statements are inaccurate and not germane to this proceeding.

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 Similarly, since the decision to run a seam/crack tool was not required under IMP, it was
not therefore subject to the prioritization process at the base of NOPV Item 4. Contrary to the
Agency’s allegations in support of Item 4, the decision to run Patoka to Conway segment first
was based on an analysis that the Patoka to Conway segment experienced (i) more hydrostatic
seam failures on a LF-ERW per mile basis; (ii) more pressure reversals; (iii) shorter theoretical
fatigue life based on existing data; and (iv) three girth weld leaks not present in Conway to
Corsicana. Also, in the same year, the Company assessed the Conway to Corsicana segment
with a magnetic flux leakage combo ILI tool. 
 

For the foregoing reasons, Items 1 – 4 of the NOPV should be dismissed or rejected
because they are neither supported by the law or facts, and they are all based on an incorrect
after-the-fact presumption: that the Company should have deemed the Pegasus Pipeline
susceptible to seam failure. PHMSA goes on to allege in Item 7 of the NOPV that Respondent
failed to consider preventative and mitigative (P&M) measures (as incorporated into the
Company’s internal procedures), by not updating its risk assessment when the voluntary TFI tool
run was delayed. As reflected by the record, that allegation is simply incorrect. The Company
revised its seam failure susceptibility analysis risk assessment in March of 2011, and it was
scheduled to be reviewed again in 2013. The re-assessment interval was conservative and no
changes had occurred that would affect the assessment. Further, no TFI seam/crack tool run was
even required, since all prior risk assessments had concluded that there was no risk of long seam
failure. Simple logic underscores how this alleged violation is without support, given that no
anomaly was reported when the Company ultimately did run the TFI tool in 2012-2013; since
crack growth is typically a time dependent threat, it was even less likely that any anomaly would
have been discovered by an earlier tool run, as suggested by the allegations in Item 7.
NOPV allegations 1 - 4 and 7, all of which rely upon PHMSA’s presumption that the
Pegasus Pipeline should have been determined to be susceptible to seam failure, are unsupported
by the facts, the law and available guidance. They also conflict with the opinions of the nation’s
leading experts on these issues. The record in this case clearly shows that Respondent did far
more than required by existing rules or guidance to identify LF-ERW pipe that is susceptible to
seam failure. In establishing its assessment schedules, the Company carefully considered all
required risk factors based on all available information, expressly including risks associated with
LF-ERW pipe. The Company subsequently completed four separate engineering analyses to
further evaluate the risk of seam failure on the Pegasus Pipeline, incorporating information from
three hydrostatic pressure tests and three in-line inspection (ILI) runs (one with a crack/seam
tool). Each analysis indicated that the line was not seam failure susceptible and the Company
performed its integrity assessments and evaluations accordingly and in compliance with the IMP
regulations and its internal procedures.
III.

PHMSA Has Not Proved Alleged Violations Nos. 5-6 or Nos. 8-9
A.

NOPV Item 5

PHMSA alleges that two locations, “MP 164.051” and “MP 142.394,” were identified as
immediate repair conditions on a preliminary report from the tool vendor that was received by
Respondent on August 9, 2010. PHMSA asserts that instead of considering this information as
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 presenting “immediate” conditions, Respondent instead treated the anomalies as confirmation or
validation digs, and that the Company did not declare them as “immediates” until the sites were
excavated. As a result, PHMSA asserted at the Hearing that Respondent was “declaring
discovery in the ditch” and failed to take appropriate actions for “immediate conditions”
pursuant to 49 C.F.R. Part 195.452(h). Transcript, p. 22, line 22. To the contrary, as set forth in
the Pre-Hearing Brief and stated in the Hearing, both of these allegations are incorrect as a
matter of fact and law, because: (1) the vendor reports were received on August 23, 2010, and
January 10, 2011, respectively; and (2) in both instances, the Company took prompt action to
efficiently and effectively remediate the anomalies, in accordance with its IMP procedures that
have been reviewed and inspected by PHMSA numerous times.
The first anomaly at Site MP 164.051 was not identified as an immediate condition
because it was estimated to be a 72% wall loss anomaly on the preliminary vendor report that
was provided to Respondent on August 23, 2010.5 Hearing Exhibits No. 23 and 24. Such an
anomaly is not classified as an “immediate” condition unless and until it is greater than 80% wall
loss. 49 C.F.R. Part 195.452(h)(4)(i)(A). The Company added tool tolerance, in accordance
with its internal procedures that exceed the regulatory requirements. Transcript, p. 29, lines 1223; Exhibit 57, Respondent’s IMP Manual, Appendix K, Validation and Repair Process (2010).6
As a result, the Company promptly took action by declaring the anomaly as a potential
“immediate” on the same day and excavated, examined and repaired it within five days. Hearing
Exhibit No. 25.7 As further explained by Respondent at the Hearing,
Our program makes an analogy between an unvalidated preliminary report and an
immediate repair and a safety related condition. So, we have five days to validate that
report and then five days to fix it. And so, we immediately convene a discussion
internally when we receive that report and begin to take those steps as if it were a safety
[related] condition. So, we repaired it within that very first five days.

                                                            
5

The NOPV erroneously states Respondent received the preliminary report on August 9, 2010, but that is a
reference from the vendor’s database, not the date information was transmitted to Respondent. PHMSA stated at the
Hearing that this was “the first time [they had] seen that [date].” Transcript, p. 26, lines 19-20. That statement is
simply unsupported by both the NOPV itself and further discussion at the Hearing. PHMSA cites to the correct
receipt in NOPV Item 6 where the correct receipt date of August 23, 2010, is set forth in the Table at p. 6 of the
NOPV, last line, second column. PHMSA attempted to suggest in the Hearing that the data must have been
available on August 9, 2010, due to the wording by the vendor in an August 23, 2010, email attached as Hearing
Exhibit 23 that “Today is the day [Respondent] wanted [the data] sent to him.” Transcript, p. 18, line 3. To the
contrary, this is simply a reference to the fact that the data was due to be provided to the Company on August 23,
2010, consistent with Respondent’s requirements that the vendor provide preliminary reports within 30 days of
completion of the 2010 Conway to Corsicana ILI. To suggest otherwise is pure conjecture on the part of the Agency
without any factual basis whatsoever.

 

6

Notably, this specific procedure has been inspected many times by PHMSA and the Agency has not cited any
concerns.
7

In this instance, the anomaly did, in fact, turn out to be an immediate with greater than 90% wall loss. Transcript,
p. 29, lines 12-19.

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 Transcript, p. 28, lines 11-19 (emphasis added); Exhibit 58, Respondent’s IMP Manual, Section
2.3.5.4.2-4 (Safety-Related Condition Requirements) (2010). In PHMSA guidance, the Agency
endorses consideration of safety-related conditions as they relate to immediate repairs.8 Further,
PHMSA guidance expressly provides for the discovery of immediates upon excavation and
examination. Exhibit 79, PHMSA Liquid IMP Frequently Asked Question (FAQ) 7.19.
The second anomaly referenced in the NOPV as Site MP 142.394 was not included in the
August 23, 2010, preliminary report at all, but instead was called out in the final report from the
vendor that was received by Respondent on January 10, 2011.9 Hearing Exhibit No. 30.
Respondent determined that this anomaly was an immediate condition based on orientation and
proximity to a high consequence area. As reflected in Hearing Exhibit 31 and related
documentation, the Company immediately scheduled the anomaly for excavation, made relevant
one call notifications, and repaired the anomaly two days later, on January 12, 2011, when it was
excavated.10
NOPV Item 5 should be dismissed for failure to state a claim given that PHMSA has not
produced evidence in support of either allegation regarding the anomalies in question, and
Respondent fully complied with the IMP rules and procedures.
B.

NOPV Item 6

PHMSA cites four occasions where Respondent allegedly failed to declare discovery of
actionable anomalies within 180 days of an ILI assessment, per 49 C.F.R. Part 195.452(h)(2),
“despite the availability of adequate information in the vendor reports to make such
determinations.” The Agency is incorrect as a matter of fact and law. In all four instances, the
Company did not receive ILI data from the vendor until near the end of the requisite 180-day
period. As a result, in all four instances, adequate information was not available and ‘discovery’
was impractical given the late transmittal of data. PHMSA’s IMP regulations and guidance
allow for situations where vendor data is received so late as to make declarations of “discovery”
within that time period impracticable. 49 C.F.R. Part 195.452(h)(2).
                                                            
8

See e.g., Exhibit 80, Notice of Amendment in re: Cenex Pipeline Company, CPF 5-2011-5018M (July 26, 2011)
(citing an operator under 49 C.F.R. Part 195.452(h) for failure to reference its safety-related condition report
procedure in its IMP manual related to immediate conditions to require a safety-related condition report where a
repair cannot be made within 5 days of determination or 10 days of discovery).
9

This is a different anomaly than cited to in the Agency’s PSVR, and at the Hearing PHMSA further confused the
issue by citing to other anomalies that are not alleged in the NOPV. Hearing Exhibit No. 32; Transcript p. 21, lines
23 – p. 22, line 17. The NOPV clearly alleges a violation with respect to an anomaly at MP 142.394, however;
given that is the specific allegation at issue, any discussion at the Hearing regarding other anomalies is simply
irrelevant.

10

Respondent has confirmed that page 3 of the PL-0751 form mistakenly identifies January 5, 2011, as the
discovery and repair date. Related documentation supports that the final report was received on January 10, 2011,
and that the repair occurred on January 12, 2011. See Hearing Exhibit No. 31 (repair form signed Jan. 12, 2011;
attached dig sheets printed on Jan. 10, 2011); Hearing Exhibit No. 27 (final ILI report and repair summary noting
receipt on Jan. 10, 2011 and repair on Jan. 12, 2011); Hearing Exhibit 30 (email correspondence regarding the final
report dated Jan. 10, 2011); see also Exhibit 59, Email from C. Gorman dated Jan. 10, 2011 (noting that date as day
zero for the potential immediate).

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 At the Hearing, PHMSA asserted additional allegations not reflected in the NOPV,
namely that, because the Company requested that the vendor provide data for four segments
together, the vendor could not have met the 180-day deadline because of the length of the entire
tool run. Transcript, p. 39, lines 8-16, 25- p. 40, line 1. PHMSA asserted that an operator must
account for both its process and the final vendor report within the 180-day period, and that an
operator cannot use the fact that a vendor provided data late in the 180-day period as the basis for
an impracticability argument. Transcript, p. 35, lines 12- p. 36, line 2.
No Agency regulation, guidance or precedent exists that governs the particular length of a
tool run in the IMP regulations. There is also little guidance on impracticability, but PHMSA
has held in other cases that there are “…situations where a delay in receiving ILI results from a
tool vendor may render the 180-day discovery period impracticable.” Exhibit 78, Final Order in
re ExxonMobil Pipeline Company, CPF 4-2011-5016, (June 27, 2013), p. 17.
Respondent has clearly demonstrated in the record that, in all four instances cited by
PHMSA, the tool vendor did not provide the Company with the ILI data until very nearly the end
of the 180-day period. This is despite express commitments by the vendor to provide
preliminary data within 30 days and final data within 90 days of completion of any ILI tool run,
in order to allow the Company sufficient time to validate and integrate the data within the
regulatory timeframe.11 In light of the late dates in which the final data was received, it was
simply not possible to verify the ILI vendor data and to conduct data integration properly.
PHMSA’s assertion that the Company knew that the vendor would not be able to provide the
final data within 180 days is inaccurate and not supported by the evidence.12 As allowed by the
IMP rules, Agency guidance and the Company’s IMP procedures, the 180-day period was
extended for acknowledged reasons, and documented in accordance with the Company’s IMP
Plan and the IMP regulations. See Hearing Figure 4 and Exhibits No. 26, 33, 38 and 39 (IMP
Forms 1.2 documenting each extension).
Given the lack of regulation or guidance that supports either of PHMSA’s allegations in
this instance, NOPV Item 6 should be withdrawn in its entirety, or alternatively, the penalty
should be substantially reduced.
C.

NOPV Item 8

The NOPV alleges that Respondent violated 49 C.F.R. Part 195.402(a) regarding
operations and maintenance (O&M) manuals, but as noted at the Hearing, the actual allegations
and facts relate to the Agency’s IMP rules under Part 195.452. Transcript, p. 63, lines 12-16. In
addition to the fact that this allegation is erroneously pleaded as a matter of law, it also fails on
                                                            
11

Specific only to the last of the four tool runs at issue, the 2013 Conway to Coriscana TFI tool run, the ILI vendor
subsequently committed to providing the preliminary data within 60 days and the final data within 90-120 days. See
e.g., Exhibit 64, Email from J. Johnson (GEPII) to P. Vocke (Respondent) (April 12, 2012).
12

See e.g., Exhibit 61, Email from L. Lamons (Respondent) to J. Johnson (GE PII) (Nov. 29, 2012); Exhibit 62,
Email from C. Gorman (Respondent) to R. Coryell (GE PII) (Dec. 3, 2012); Exhibit 63, Email from C. Gorman
(Respondent) to B. Hagerman (GE PII) (Mar. 15, 2013).

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 the merits because Respondent did comply with the relevant integrity management regulations
and its procedures.
PHMSA alleges under NOPV Item 8 that Respondent violated O&M provision 49 C.F.R.
Part 195.402(a) by selectively using its IMP threat identification and risk assessment (TIARA)
process in violation of its IMP manual (which resulted in the failure to characterize the risk of a
release to certain areas). The regulation cited, 49 C.F.R. Part 195.402(a), however, is wholly
unrelated to the allegations, which instead are founded on the IMP rules at 49 C.F.R. Part
195.452. See 49 C.F.R. Part 195.402(a) (requiring operators to prepare and follow a manual of
written procedures for “conducting normal operations and maintenance activities and handling
abnormal operations and emergencies.”). For that reason, the Presiding Officer should dismiss
(or PHMSA should withdraw) this alleged violation. Such action would be consistent with past
enforcement precedent. See Exhibit 76, Final Order in re Rocky Mountain Pipeline System,
LLC, CPF 5-2004-5001 (Dec. 11, 2006) p. 7 (withdrawing the alleged violation “because the
regulation cited does not relate to the alleged problem.”).
Even if the claim in Item 8 is allowed to stand although incorrectly pleaded, the record
clearly shows that Respondent properly applied its integrity management procedures under
TIARA. The TIARA model did not identify any threats or require any P&M measures.13 Using
this software, and in consideration of recommendations and analysis performed by the engineers
familiar with the Pipeline, the Company implemented P&M measures, including scheduling of
three emergency flow restrictive devices and the decision to run a TFI seam/crack tool.
As explained at the Hearing, the Company’s TIARA analysis assesses threats on a
forward-looking basis for the next five years based on information regarding the design,
construction, operation and maintenance of the pipeline until the next reassessment. As such,
part of the analysis would include the knowledge that a seam tool would be run during the next
five year interval. The TIARA risk score for each threat is then examined and analyzed by the
Company for sensitivity to varying inputs. Specific to the 2011 TIARA analysis and risk
assessment on the Conway to Corsicana segment, Respondent included comments in the TIARA
inputs and performed a hypothetical threat analysis to better understand the sensitivities of the
TIARA software and identify the conditions under which the model would have identified a
manufacturing threat. Even though the actual (as opposed to hypothetical) TIARA analysis did
not identify any threats, based on the recommendations from its engineers, the Company
nonetheless implemented additional P&M measures to protect the pipeline, expressly addressing
sensitive areas and drinking water bodies along the Pegasus Pipeline.
Item 8 should either be dismissed or withdrawn because it fails to state a claim, and
because it is based on an inaccurate reading of facts and application of the law.

                                                            
13

In compliance with the Company’s TIARA procedures, the only notification provided to management was OIMS
2A Attachment #7 which conveyed the risk score. Exhibit 60, Email from M. Weesner (Respondent) approving
OIMS 2A Attachment #7 (Mar. 15, 2011). No other management notifications or approvals were required under
TIARA or OIMS 2A because there were no elevated threats.

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 D.

NOPV Item 9

PHMSA alleges that Respondent failed to follow its own IMP procedures by not creating
Management of Change (MOC) documentation when the decision was made to merge test
segments for ILI purposes. Item 9 asserts a violation of 49 C.F.R. Parts 195.452(b)(5) and (j)(1).
PHMSA goes on to assert that it is the failure to follow the MOC procedures that allowed the
testable segments to be merged and resulted in a dilution of the TIARA risk scores. As clearly
reflected in the record and further discussed at the Hearing, however, it is evident that
Respondent did in fact create not one, but two MOC forms to support its decision, following a
risk analysis conducted in 2005 that specifically considered the impact of the merger of testable
segments on IMP ILI assessments. Hearing Exhibits No. 10 and 11.
Respondent’s risk analysis in 2005 expressly considered the impact of the merger of
testable segments on IMP ILI assessments. Respondent concluded that there would be no
negative impact to the integrity risk assessment process. This analysis is reflected in the two
MOC forms that Respondent produced to PHMSA, in compliance with the Company’s OIMS
procedure 7.2.14 Id. As explained in the Hearing, under Respondent’s TIARA program,
dynamic risk assessment threats cannot be aggregated or masked over multiple miles and,
therefore, the length of a testable segment simply does not impact the identification of threats.
See Transcript, p. 69, line 23 – p. 70, line 12. Accordingly, PHMSA’s NOPV Item 9 as alleged
should be withdrawn.15
IV.

The Proposed Penalty Should be Withdrawn, or Alternatively, Substantially
Reduced

As the Agency admitted during the Hearing, there is no strict liability under the PSA.
Transcript, p. 84, lines 21-23. The occurrence of an incident is not by itself a basis for a
violation or penalty. Because Respondent complied with all applicable rules, no penalty should
apply. Even if violations are deemed to have occurred, the amount of penalty is not warranted
and should be significantly reduced in compliance with the PSA.16 NOPV Items 1 – 4 and 7 are
so closely related for penalty purposes, by sharing the same elements of facts and law, that they
constitute a “related series of violations” subject to the PSA statutory penalty maximum of $1
million in the aggregate. Further, all of the penalties proposed under the NOPV should be
reduced in consideration of the required statutory mitigation factors.
                                                            
14

The overall risk for potential leaks was reduced by the removal of pig traps, which included removal of potential
sources of leaks (redundant piping, valves, flanges, and fittings). As a result, the MOC form did not require a risk
assessment. With respect to consideration of any impact to ILI report timing, those considerations are addressed by
the Part 195 regulatory timeframe and ILI vendor contract specifications.
15

Throughout the Hearing, much of the discussion regarding NOPV alleged violations went well beyond the
allegations pleaded in the NOPV itself. The discussion surrounding NOPV Item 9 was no exception, a point
acknowledged by PHMSA counsel. Transcript, p. 74, lines 6-8. The extraneous discussions have no bearing on the
allegations pled by PHMSA and are therefore to be ignored in this proceeding.
16

As noted by PHMSA counsel in the Hearing, the proposed penalty in the NOPV is an “initial … starting point,” or
a “cap” and adjustment of the penalty will be considered by taking into account mitigating points made at the
Hearing. Transcript, p. 150, lines 17 – p. 151, line 7.

 

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 A.

Items 1-4 and 7 are “Related” for Penalty Purposes

NOPV Items 1 – 4 and 7 are related because they rely on the same facts and law and
should constitute a single violation subject to the statutory $1 million penalty maximum for
“related series of violations.” 49 U.S.C. § 60122(a)(1); 49 C.F.R. Part 190.223(a). All of these
alleged violations rely on the Agency’s argument that Respondent failed to consider that the
segment was susceptible to seam failure. Assessing five separate penalties that when combined
exceed $1 million, based on the same facts and applicable law, contradicts the plain language of
the PSA, the Agency’s rules and the Agency’s only guidance issued to date on the subject.
The PSA requires that “any related series of violations” occurring prior to January 3,
2012 must be capped at no more than $1 million. 49 U.S.C. § 60122(a)(1); 49 C.F.R. Part
190.223(a). The only legislative history on point indicates that this phrase should be applied in
regard to a single incident.17 Further, the only relevant guidance articulated by the Agency to
date states that a related series of violations should include the situation where the facts and law
for multiple claims “are so closely related…that they are not separate and should be considered
one violation.” Exhibit 77, Final Order in re: Colorado Interstate Gas Co., CPF 5-2008-1005
(Nov. 23, 2009).
The facts and law underlying NOPV Items 1 – 4 and 7 are inextricably intertwined and
stem from one underlying PHMSA allegation. But for the Agency’s allegation that the
Respondent failed to conclude that the pipe segment was susceptible to seam failure, there would
not be a basis for the purported violations asserted in Items 1 – 4 and 7. Item 1 addresses the
alleged failure to conclude that the pipe was susceptible to seam failure. Item 2 builds on that
allegation to assert that because Respondent did not make this conclusion, it exceeded the length
of time allowed to run a seam ILI tool. In turn, Item 3 alleges that Respondent failed to complete
a Management of Change form for extending the five year reassessment interval allegedly
violated under Item 2. Similarly, Item 4 alleges again that because Respondent failed to
conclude the pipe was susceptible to seam failure, it did not properly prioritize the timing of ILI
seam tool runs. In Item 7 of the NOPV, PHMSA asserts that by not updating its risk assessment
when the seam tool was delayed, the Respondent failed to follow certain internal procedures.
This is further underscored by the Agency’s PSVR, which cites the same evidence in support of
these Items. PHMSA PSVR, CPF 4-2013-5027, pp. 7, 13, 26 (describing the relevant evidence to
include hydrostatic pressure test data and IMP assessment worksheet and risk assessments); and
pp. 19 and 45 (describing the relevant evidence to include IMP risk assessments, analyses and
IMP Form 2.3).

                                                            
17

During reauthorization efforts that preceded the enactment of the Pipeline Safety Improvement Act of 2002,
Senators had the following exchange regarding “related series of violations”: [Sen. Hollings]: “I am seeking
clarification that all information requests issued by the Secretary pursuant to a single incident investigation are
considered “related” for purposes of calculating the $1,000,000 civil penalty cap for a ‘related series of
violations’…” [Sen. Kerry]: “it is the intention of this legislation to treat all information requests pursuant to a
single incident investigation as ‘related’ for purposes of applying the civil penalty cap…” Exhibit 81, Senator
Hollings (SC) and Senator Kerry (MA). “Pipeline Safety Improvement Act.” Congressional Record 146:103 (Sept.
7, 2000), p. S8235.

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 B.

Any Penalty Must Consider All Mitigating Factors

In addition to the above, the proposed penalty fails to account for relevant statutory
mitigation factors required under the Pipeline Safety Act, including good faith and cooperation.
49 U.S.C. § 60122(b); 49 C.F.R. Part 190.225. In assessing a penalty, the Agency must (“shall”)
consider the nature of the violation, circumstances, gravity, culpability and good faith in
attempting to achieve compliance. Id. The Agency’s PSVR failed to appropriately apply these
factors, however, despite evidence in the record demonstrating that Respondent clearly complied
with applicable regulatory requirements under IMP and did not at any time make conscious
decisions to disregard the law.
In addition, the proposed penalty does not appear to consider the fact that Respondent
was prompt, diligent and thorough in responding to and investigating the incident. The Agency
acknowledges this fact in the PSVR. Exhibit B to PHMSA PSVR, CPF 4-2013-5027 (Accident
Report), pp. 11, 14 (noting that Respondent’s response to the incident was timely, appropriate
and in accordance with its procedures). To date, Respondent has spent over $75 million in
response to the Mayflower incident and continues to review and revise its procedures in
consideration of its incident investigation.
Finally, the proposed penalty should be reduced because PHMSA failed to expressly
allege multi-day or statutory maximum claims in the NOPV in violation of due process and
procedural requirements of the Administrative Procedure Act (APA). The APA requires that
respondents in any enforcement proceeding be informed of the “matters of fact and law
asserted.” 5 U.S.C. 554(b). This should include a clear statement of the theory on which the
agency will proceed with its case, such that respondent can understand the issues and is afforded
full opportunity to present its defense at a hearing. Yellow Freight System v. Martin, 954 F.2d
353, 357 (6th Cir. 1992). PHMSA’s NOPV fails to satisfy these basic requirements because it
does not provide any explanation of how the penalty was derived, including whether it alleges
multi-day or statutory maximum claims. The proposed penalty should be reduced accordingly,
as a matter of equity, policy, and in light of due process considerations.
For all of the reasons noted above, the proposed penalty should be significantly reduced.
 

V.

The Compliance Order is Overbroad and Unnecessary

The Proposed Compliance Order (PCO) should be withdrawn because Respondent complied
with the IMP regulations, thus there is no basis for a finding of violation that would allow issues
of a PCO. In addition, the PCO is both overbroad and unnecessary and, as such, constitutes an
abuse of agency discretion.
The PCO directs Respondent to undertake activities on “all assets,” not just the Pegasus Pipeline.
There is no authority under the PSA or the Agency’s rules to apply incident-specific corrective
actions in a NOPV to other company assets.18 In addition, established federal case law requires
                                                            
18

At the Hearing, PHMSA incorrectly estimated that 80% of ExxonMobil Pipeline Company and Mobil Pipeline
Company assets are pre-1970 ERW. Transcript, p. 154, lines 14-15. In actuality, the companies own or operate
pipelines consisting of roughly 50% of LF-ERW pipe.

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 that injunctive relief be narrowly tailored to the specific harm alleged (not potential harm) and
that an overboard scope of injunctive relief is an abuse of discretion. Ahearn ex rel. N.L.R.B. v.
Remington Lodging & Hospitality, 842 F.Supp.2d 1186, 1205-06 (D. Alaska 2012) (appeal
dismissed Apr. 6, 2012) citing Stormans, Inc. v. Selecky, 586 F.3d 1109, 1140 (9th Cir. 2009).
Yet, the PCO does just that. PCO, Paragraph 1 (requiring review and revision of the
Company’s IMP Plan for “all pre-70 ERW pipe on any assets covered by the operator’s IMP”)
(emphasis added).
In addition, the PCO is unnecessary. The IMP regulations require continual evaluation of risk to
a pipeline’s integrity, regardless of whether incidents have occurred or violations are alleged. 49
C.F.R. Part 195.452(j). For this reason, and as a prudent operator, Respondent has already
begun work on virtually all actions addressed in the PCO and expects to address all of the
elements of the PCO.19
In light of the above, the PCO should be withdrawn or, at a minimum, modified to tailor the
corrective actions to the assets at issue.
VI.

Summary and Request for Relief

PHMSA closely audited the Pegasus Pipeline in 2007, including a specific and intensive review
of Respondent’s seam failure engineering analyses. Despite four PHMSA inspectors spending a
full week on the review, the Agency did not find any flaws in the Respondent’s IMP plan or
implementation of its LF-ERW seam risk process. Even after the 2013 incident, the nation’s
leading experts in LF-ERW threat analysis and pipeline risk management who submitted
affidavits for this matter concluded the Mayflower incident was not capable of either prediction
or reliable detection using existing technology and methods. The Agency’s own most recent
Battelle report on ERW pipe risk generally, commissioned by PHMSA at the repeated request of
NTSB and issued after this incident, similarly concluded that technology is not yet capable of
finding such unusual anomalies as that causing the Mayflower incident. That conclusion is in
stark contrast to the NOPV’s bold after the fact assertion that “there was more than adequate
information” to conclude that a specific risk existed. The record reveals that the anomaly
causing this incident was not capable of prediction or reliable detection by technology and
methods of inspection used at the time in compliance with applicable law. Moreover,
Respondent not only complied with applicable law in considering the risk of seam failure, it
actually did more than what is legally required regarding consideration of the risk of LF-ERW
seam failure.
The Agency has issued relatively little regulation or guidance over the years on how to consider
or identify the risk of LF-ERW seam failure. Despite this lack of direction, Respondent clearly
did have a written IMP Plan in place that carefully considered the risk of seam failure of its LFERW pipe, in compliance with the minimal legal requirements and PHMSA guidance available,
and consistent with industry standards on this issue. In fact, Respondent reviewed the risk of
seam failure numerous times, over many years, using dozens of in-house and consulting
engineers to review the data, analyses and conclusions. Three separate hydrotests were
                                                            
19

 In addition, the timeframes set forth in the PCO, including Paragraph 1, are both unreasonable and unworkable. 

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 performed, along with three ILI runs (one being a seam/crack tool), and four separate seam
failure engineering analyses.
The alleged violations in Items 1 – 4 and 7 of the NOPV are unsupported by the record in this
case because they presume a failure to conduct a seam analysis, which is controverted by the
facts. In addition, there are errors and inconsistencies in the NOPV which were not explained by
the Agency in the Hearing. In light of such errors, Items 5, 6, 8 and 9 go unsupported by the
evidence. Item 8 should also be dismissed for failure to state a claim, because it asserts a
violation of the Agency’s O&M program rules, but discusses facts related to the Agency’s IMP
rules.
Even if the alleged violations were proved, the amount of penalty proposed should be
significantly reduced. Items 1 – 4 and 7 are a “related series of violations” for penalty purposes,
meaning they should be combined to a single claim and then subject to the statutory penalty cap.
The Agency also failed to apply mitigating factors required by the statute in proposing a penalty.
Finally, the PCO is both illegally overbroad, and unnecessary, in light of the fact that existing
IMP regulations require such ‘continual evaluation’ of risk factors and analyses proposed in the
Compliance Order.
For all of these reasons, and in consideration of other matters as justice may require, the NOPV
(including the Proposed Civil Penalty and the Proposed Compliance Order), should be
withdrawn in its entirety. In the alternative, the claims asserted should be revised, the penalty
substantially reduced and the Compliance Order substantially modified.
Respectfully submitted,

_____________________________
HUNTON & WILLIAMS
Robert E. Hogfoss, Esq.
Bank of America Plaza, Suite 4100
600 Peachtree Street, N.E.
Atlanta, GA 30308
(404) 888-4042
Catherine D. Little, Esq.
Bank of America Plaza, Suite 4100
600 Peachtree Street, N.E.
Atlanta, GA 30308
(404) 888-4047

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 EXXONMOBIL PIPELINE COMPANY
Troy A. Cotton, Esq.
General Counsel
800 Bell Street
Houston, Texas 77002
(832) 624-7922
Johnnie R. Randolph, Esq.
Counsel
800 Bell Street
Houston, Texas 77002
(832) 624-7925
Date: July 25, 2014

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 Index of Attached Exhibitszo

 

No. Exhibit

 

57 IMP Manual, Appendix K, Validation and Repair Process (2010)

 

58 IMP Manual, Sections 2.3.5.4.2-4 (Safety-Related Condition Requirements)
(2010)

 

59 Email from C. Gorman to IMP team (Jan. 10, 2011)

 

60 Email from M. Weesner approving OIMS 2A Attachment #7 (Mar. 15, 2011)

 

61 Email from L. Lamons to J. Johnson (GE PII) (Nov. 29, 2012)

 

62 Email from C. Gorman to R. Coryell (GE PII) (Dec. 3, 2012)

 

63 Email from C. Gorman to B. Hagerman (GE PII) (Mar. 15, 2013)

 

 

64 GE PII Email from J. Johnson to P. Vocke (Apr. 12, 2012)

 

 

 

2? The Exhibit references set forth in this Index continue from the Hearing Exhibits referenced and included with
Respondent?s Pre-Hearing Brief and discussed at the Hearing.

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Index of Exhibits Included by Reference21

 

No. Exhibit

 

65 Battelle Institute, ?Final Interim Report? on ERW Seam Failures (Sept. 20, 2012)

 

66 Battelle Final Summary Report on ERW Seam Failures (Oct. 23, 2013)

 

67 Battelle ERW Study, 12?h Quarterly Report (May 31, 2014)

 

68 NTSB Accident Report (Carmichael, MS), (Nov. 1, 2007)

 

69 NTSB Safety Recommendation to PHMSA (Oct. 27, 2009)

 

70 NTSB Letter to PHMSA (Dec. 29, 2010)

 

71 NTSB Letter to PHMSA (Oct. 19, 2011)

 

72 OPS Alert ALN-88-01 (Jan. 28, 1988)

 

73 OPS Alert (Mar. 8, 1989)

 

74 OPS Final Rule, 59 Fed. Reg. 29379 (June 7, 1994)

 

75 OPS Final Rule, 65 Fed. Reg. 75378 (Dec. 1, 2000)

 

76 PHMSA Final Order, In re Rocky Mountain Pipeline System, LLC, CPF 5-2004-5001
(Dec. 11, 2006)

 

77 PHMSA Final Order, In re: Colorado Interstate Gas Co., PHMSA CPF 5-2008-1005
(Nov. 23, 2009)

 

78 PHMSA Final Order, In re: ExxonMobil Pipeline Company, PHMSA CPF 4-2011-5016
(Jun. 27, 2013)

 

79 PHMSA Liquid IMP Frequently Asked Question (FAQ) 7.19

 

80 PHMSA Notice of Amendment, In re Cenex Pipeline Company, PHMSA CPF 5-2011?
5018M (July 26, 2011)

 

 

81 "Pipeline Safety Improvement Act," Congressional Record 1462103 (testimony of
Senator Hollings and Senator Kerry) (Sept. 7, 2000)

 

 

 

2? These documents should be considered part of the record in this matter, but they have not been attached with this
submission because they are publically available.

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