# ENABLE GAS TRANSMISSION, LLC — Notice of Probable Violation

**Citation:** CPF 420071004  
**Type / status:** enforcement / historical  
**Agency:** Pipeline and Hazardous Materials Safety Administration  
**Effective:** Not stated  
**Published:** 2007-03-29

CLOSED notice of probable violation citing 192.917(a), 192.917(c), 192.917(e)(1), 192.917(e)(4), 192.925(b), 192.925(b)(1), 192.927(c)(1)(i), 192.927(c)(5)(ii), 192.929(b)(1), 192.935(c).

## Document text

Notice of Probable Violation involving ENABLE GAS TRANSMISSION, LLC. PHMSA's enforcement data identifies the cited regulations as 192.917(a),  192.917(c),  192.917(e)(1),  192.917(e)(4),  192.925(b),  192.925(b)(1),  192.927(c)(1)(i),  192.927(c)(5)(ii),  192.929(b)(1),  192.935(c). The case was opened on 2007-03-29 and is reported as closed as of 2012-01-23. Proposed civil penalty: $95,000. Assessed civil penalty: $51,000. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

420071004_Closure Letter_01232012.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071004/420071004_Closure%20Letter_01232012.pdf

420071004_Closure Letter_01232012_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071004/420071004_Closure%20Letter_01232012_text.pdf

420071004_FinalOrder_02112011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071004/420071004_FinalOrder_02112011.pdf

420071004_FinalOrder_02112011_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071004/420071004_FinalOrder_02112011_text.pdf

420071004_Notice Letter_03292007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071004/420071004_Notice%20Letter_03292007.pdf

420071004_operator response to notice_09282007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071004/420071004_operator%20response%20to%20notice_09282007.pdf

420071004_Closure Letter_01232012_text.pdf

CERTIFIED MAIL - RETURN RECEIPT REQUESTED
January 23, 2012
Mr. Walter Ferguson
Division Sr. VP MidStream Field Operations, Engineering & Construction
CenterPoint Energy Gas Transmission, LLC
P.O. Box 21734
Shreveport, Louisiana 71151
CPF 4-2007-1004
Dear Mr. Ferguson:
On February 11, 2011, the Pipeline and Hazardous Materials Administration issued a Final Order
to CenterPoint Energy Gas Transmission Company (CenterPoint) in the referenced case. Based
on review of the documentation you provided and confirmation that the administrative civil
penalty has been paid, it has been determined that CenterPoint has complied with the terms and
conditions of the Final Order.
Accordingly, PHMSA now considers this case closed and no further action is contemplated with
respect to the maters involved in this case.
Thank you for your cooperation in this matter.
Sincerely,
R. M. Seeley
Director, Southwest Region
Pipeline and Hazardous
Materials Safety Administration

420071004_FinalOrder_02112011_text.pdf

FEB 11 2011
Mr. Pete Kirsch
Division Senior Vice President
Pipeline, Operations and Engineering
CenterPoint Energy Gas Transmission Company
P.O. Box 1700
Houston, Texas 77210-1700
Re: CPF No. 4-2007-1004
Dear Mr. Kirsch:
Enclosed please find the Final Order issued in the above-referenced case. It makes findings of
violation, withdraws certain allegations of violation, and assesses a reduced civil penalty of
$51,000. The Final Order also specifies certain actions that need to be taken by CenterPoint to
comply with the pipeline safety regulations. The penalty payment terms are set forth in the Final
Order. When the civil penalty has been paid and the terms of the compliance order completed,
as determined by the Director, Southwest Region, this enforcement action will be closed. Your
receipt of the Final Order constitutes service of that document under 49 C.F.R. § 190.5.
Thank you for your cooperation in this matter.
Sincerely,
Jeffrey D. Wiese
Associate Administrator
for Pipeline Safety
Enclosure
cc: Mr. R.M. Seeley, Director, Southwest Region, PHMSA
Mr. Kenneth B. Driver, Esq.
Counsel for CenterPoint Energy Gas Transmission
Jones Day
51 Louisiana Avenue, N.W.
Washington, D.C. 20001
CERTIFIED MAIL – RETURN RECEIPT REQUESTED [7005 1160 0001 0041 3221]



U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, D.C. 20590
_____________________________________________
In the Matter of )
CenterPoint Energy Gas Transmission Company, )
Respondent. )
)
)
)
)
) CPF No. 4-2007-1004
_____________________________________________)
FINAL ORDER
On September 12-16, and November 14-18, 2005, pursuant to 49 U.S.C. § 60117, a
representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office
of Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of the Integrity
Management Program records of CenterPoint Energy Gas Transmission Company (CenterPoint
or Respondent), in Shreveport, Louisiana.
approximately 8,200 miles of interstate natural gas pipelines, of which 186 miles were covered
by its Integrity Management Program (IMP).
1 At the time of the inspection, Respondent operated
As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to
Respondent, by letter dated March 29, 2007, a Notice of Probable Violation, Proposed Civil
Penalty, and Proposed Compliance Order (Notice). In accordance with 49 C.F.R. § 190.207, the
Notice proposed finding that CenterPoint had violated 49 C.F.R. §§ 192.917(a), 192.917(c),
192.917(e)(1), 192.917(e)(4), 192.925(b)(1), 192.927(c)(1)(i), 192.927(c)(5)(ii), 192.929(b)(1),
and 192.935(c) and proposed assessing a civil penalty of $95,000 for the alleged violations. The
Notice also proposed ordering Respondent to take certain measures to correct the alleged
violations.
CenterPoint responded to the Notice by letter dated April 30, 2007. Respondent contested the
allegations and requested a hearing. In advance of the hearing, by letter dated September 28,
2007, CenterPoint submitted an additional response detailing its arguments and providing
supporting documents (Response). A hearing was subsequently held on October 11, 2007, in
Houston, TX, with an attorney from the Office of Chief Counsel, PHMSA, presiding.
Respondent was represented by counsel in this proceeding. After the hearing, CenterPoint
provided a Post-Hearing Submission by letter dated November 13, 2007 (Closing).
1 CenterPoint Energy Gas Transmission Company is an indirect, wholly-owned subsidiary of CenterPoint Energy,
Inc.



2
FINDINGS OF VIOLATION
The Notice alleged that Respondent violated 49 C.F.R. Part 192, as follows:
Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 192.917(a), which states:
§ 192.917 How does an operator identify potential threats to pipeline
integrity and use the threat identification in its integrity program?
(a) Threat identification. An operator must identify and evaluate all
potential threats to each covered pipeline segment. Potential threats that
an operator must consider include, but are not limited to, the threats listed
in ASME/ANSI B31.8S (incorporated by reference, see § 192.7), section
2, which are grouped under the following four categories:.….
(1) Time dependent threats such as internal corrosion, external
corrosion, and stress corrosion cracking;
(2) Static or resident threats such as third party damage and outside
force damage; and
(3) Time independent threats such as third party damage and outside
force damage; and
(4) Human error.
The Notice also recited the relevant portion of ASME B31.8S, section 2, which states:
ASME B31.8S, Section 2.2, Integrity Threat Classification
The interactive nature of threats (i.e., more than one threat occurring
on a section of pipeline at the same time) shall also be considered. An
example of such an interaction is corrosion at a location that also has third
party damage.2
The Notice alleged that Respondent violated 49 C.F.R. § 192.917(a) by failing to identify or
evaluate in its IMP the potential for interactive threats to each covered pipeline segment.
Specifically, it alleged that CenterPoint’s procedures contained no process to ensure that multiple
threats on the same pipeline were evaluated for interrelated effects.3
CenterPoint contested this allegation, arguing that it used a risk assessment model to add
together the individual failure-likelihood values for each threat category, to reach an overall risk
score.
provided a measure of the interactive nature of threats. CenterPoint also indicated that it was not
aware of any published standards beyond ASME B31.8S (ASME Standard) explaining how the
company was supposed to evaluate “interactive” threats. Respondent maintained that its
procedure appropriately considered the interactive nature of threats.
4 Respondent contended that by adding together different threats, the resulting score
2 AM. SOCIETY OF MECHANICAL ENGINEERS, “MANAGING SYSTEM INTEGRITY OF GAS PIPELINES”, ASME
STANDARD B31.8S-2004 § 2.2 (JANUARY 14, 2005).
3 Notice at 1-2, citing CenterPoint Energy Gas Transmission Procedure PS-03-01-216, “Threat Identification and
Risk Assessment,” Section 2.2.
4 Response at 4-7.



3
At the hearing, OPS argued that CenterPoint’s process of simply adding the scores of various
threats did not constitute an adequate analysis of interactive threats. OPS explained that the
combined threat posed by numerous threats could be greater than the sum of those threats
individually. On that basis, OPS argued that Respondent’s process of simply adding threat
scores did not reflect the complex relationship between multiple threats. For example, OPS
indicated that the combined threats presented by internal corrosion and pipeline seam issues, at
the same location, would be much greater than the sum of those threats if assessed individually.
At the hearing and in its Closing, CenterPoint maintained its objection to this allegation.
Respondent argued further that neither the regulation nor the referenced ASME Standard
expressly requires that a “plus” factor be used when any two risk factors are present on the same
covered segment.5
CenterPoint is correct that nothing in the regulation or the ASME Standard expressly requires a
“plus” factor. Section 192.917(a) simply requires that the interactive nature of threats be
considered. However, the lack of specificity in the regulation does not mean that it is acceptable
to conduct a risk analysis which does not provide an accurate indication of the synergy of
multiple threats. Respondent did not dispute the agency’s contention that a combination of
threats might well produce a greater threat than the various threats assessed individually; rather,
it argued that in the absence of more specific guidance, it was permissible to simply add the
threat scores.
The Integrity Management regulations are designed to be flexible and permit CenterPoint to
come up with a process for threat evaluation that is best suited to its particular pipeline system
and operations. However, such flexibility does not mean that Respondent may simply add threat
scores and disregard the undisputedly more complex relationship among threats. The intent of a
threat evaluation process is to provide an operator with a sophisticated and accurate measure of
the individual and combined threats facing its pipeline system, so that it may address these
threats and reduce pipeline integrity risks. Respondent need not use any specific “plus” factor or
any other particular logarithm or process. Rather, the regulations give CenterPoint the flexibility
to develop a procedure that realistically assesses the interactive nature of threats. Only through
such a realistic assessment, however, will Respondent have an accurate indication of the
potential threats to the integrity of its system.
Accordingly, based upon a review of all of the evidence, I find that Respondent violated
§ 192.917(a) by failing to identify or evaluate in its IMP the potential for interactive threats on
each covered pipeline segment.
Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 192.917(c), which states:
§ 192.917 How does an operator identify potential threats to pipeline
integrity and use the threat identification in its integrity program?
(a) ….
(c) Risk assessment. An operator must conduct a risk assessment that
follows ASME/ANSI B31.8S, section 5, and considers the identified
threats for each covered segment….
5 Closing at 4.



4
The Notice alleged that Respondent violated 49 C.F.R. § 192.917(c) by failing to conduct a risk
assessment in accordance with Section 5 of ASME B31.8S. Specifically, it alleged that
CenterPoint did not provide documentation in its IMP to support the conclusion that the
company could eliminate certain threats from its risk assessment for High Consequence Areas
(HCAs) along its pipeline.
for risk assessments in a prescriptive integrity management program.
6 Section 5 of the ASME Standard requires minimum data and criteria
CenterPoint argued that its risk assessment did include a proper consideration of the required
minimum data and criteria for risk assessment to support the elimination of certain threats.
Respondent cited its procedures and numerous sections of the ASME Standard in support of
its contention that its risk assessment process used the latest available data to determine if
CenterPoint’s procedures that were in question but, rather, that Respondent had no
threats could be eliminated.7 At the hearing, OPS explained that it was not the adequacy of
documentation of having applied these procedures to its pipeline system.
CenterPoint responded that it had used the latest data each time it ran the risk assessment model,
to determine the threats on its system and whether any threats could be eliminated. However,
Respondent provided no documentation of its application of the risk assessment model to the
actual pipeline system data. In the absence of such evidence, PHMSA is unable to verify
whether the elimination of a particular threat was appropriate or not. Improper elimination could
result in HCAs not being properly assessed for the actual threats presented. If a threat is
improperly eliminated, it could cause or contribute to a pipeline failure and cause harm to the
public, property or the environment. For any given HCA segment where CenterPoint has
eliminated a threat, Respondent must provide some evidence in support of its decision.
Accordingly, I find that Respondent violated § 192.917(c) by failing to conduct a risk assessment
that followed Section 5 of ASME B31.8S, by providing documentation for its decision to
eliminate certain threats from its HCAs.
Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 192.917(e)(1), which states:
§ 192.917 How does an operator identify potential threats to pipeline
integrity and use the threat identification in its integrity program?
(a) ….
(e) Actions to address particular threats. If an operator identifies any
of the following threats, the operator must take the following actions to
address the threat.
(1) Third party damage. An operator must utilize the data integration
required in paragraph (b) of this section and ASME/ANSI B31.8S,
Appendix A7 to determine the susceptibility of each covered segment to
the threat of third party damage. If an operator identifies the threat of
third party damage, the operator must implement comprehensive
6 A “High Consequence Area” is an area defined as either a Class 3 location or Class 4 location under § 192.5; any
area in a Class 1 or Class 2 location where the potential impact radius is greater than 660 feet (200 meters) and the
area within a potential impact circle contains 20 or more buildings intended for human occupancy; or as further
defined in 49 C.F.R. § 192.903.
7 Response at 8-13.



5
additional preventive measures in accordance with § 192.935 and monitor
the effectiveness of the preventive measures. If, in conducting a baseline
assessment under § 192.921, or a reassessment under § 192.937, an
operator uses an internal inspection tool or external corrosion direct
assessment, the operator must integrate data from these assessments with
data related to any encroachment or foreign line crossing on the covered
segment, to define where potential indications of third party damage may
exist in the covered segment.
An operator must also have procedures in its integrity management
program addressing actions it will take to respond to findings from this
data integration.
The Notice alleged that Respondent violated 49 C.F.R. § 192.917(e)(1) by failing to have a
procedure or process to integrate data from internal inspection tools and External Corrosion
Direct Assessment (ECDA) with data related to encroachments or foreign line crossings on
certain covered segments, in order to define where potential indications of third-party damage
might exist. Specifically, it alleged that CenterPoint’s procedures did not include processes for
the integration of such data.8
Respondent admitted that its procedures “did not specifically state that the data from ECDA and
foreign line crossings would be integrated.”9 However, CenterPoint argued that such data was
integrated as part of its ECDA process; the company provided numerous supporting documents
in support of its position.
integrated some data, they do not demonstrate that Respondent had a written procedure in place,
as required by the regulation. In the absence of such a procedure for data integration, there is no
mechanism by which Respondent could consistently and accurately integrate assessment data
with data on third-party damage. Accordingly, upon review of all of the evidence, I find that
Respondent violated 49 C.F.R. § 192.917(e)(1) by failing to have a procedure or process for
integrating data from internal inspection tools and ECDA with data related to encroachments or
foreign line crossings on each covered pipeline segment.
10 While these documents may indeed indicate that CenterPoint
Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 192.917(e)(1), as quoted
above, by failing to integrate data from internal inspection tools and ECDA with data related to
encroachments and foreign line crossings on specific covered segments, in order to define where
potential indications of third-party damage might exist. Specifically, it alleged that CenterPoint
failed to integrate such data when it performed ECDA assessments for the ALE, BT-1, and A-
206 pipelines. At the hearing, CenterPoint provided documents showing that the company had,
in fact, performed data integration on these pipelines.11
Accordingly, based upon a review of all
of the evidence, I order that Item 4 be withdrawn.
8 Notice at 3, citing CenterPoint Procedures PS-03-01-110, GATHER, REVIEW AND INTEGRATE DATA; and PS-03-
01-216, THREAT IDENTIFICATION and RISK ASSESSMENT.
9 Response at 16.
10 Id.
11 Response at 19, Attachments 3.1-4.6.



6
Item 5: The Notice alleged that Respondent violated 49 C.F.R. § 192.917(e)(4), which states:
§ 192.917 How does an operator identify potential threats to pipeline
integrity and use the threat identification in its integrity
program?
(a) . . . .
(e) Actions to address particular threats. If an operator identifies any
of the following threats, the operator must take the following actions to
address the threat.
(1) ….
(4) ERW pipe. If a covered pipeline segment contains low frequency
electric resistance welded pipe (ERW), lap welded pipe or other pipe that
satisfies the conditions specified in ASME/ANSI B31.8S, Appendices
A4.3 and A4.4, and any covered or noncovered segment in the pipeline
system with such pipe has experienced seam failure, or operating pressure
on the covered segment has increased over the maximum operating
pressure experienced during the preceding five years, an operator must
select an assessment technology or technologies with a proven application
capable of assessing seam integrity and seam corrosion anomalies. The
operator must prioritize the covered segment as a high risk segment for the
baseline assessment or a subsequent reassessment.
The Notice alleged that Respondent violated 49 C.F.R. § 192.917(e)(4) by failing to specify an
assessment method for each covered segment to identify anomalies associated with the specific
threat identified for that segment. Specifically, the Notice alleged that CenterPoint’s Baseline
Assessment Plan (BAP) did not identify an assessment technology with a proven application
capable of assessing seam integrity and seam corrosion anomalies for covered pipe segments that
contained ERW pipe and had experienced either seam failure or the operating pressure had
exceeded maximum operating pressure within the last five years. Section A4 of ASME B31.8S
states that “pressure testing must be performed to address the seam issue.
allowed for either a hydrotest or the use of a Transverse Flux Inspection (TFI) tool; however,
Section A4.4 of the ASME Standard only permits a hydrotest when assessing seam threats. A
TFI tool is not an acceptable method of integrity assessment in this case.
”12 CenterPoint’s BAP
Respondent admitted that its assessment tool selection guide mistakenly permitted the use of a
TFI tool in response to a pressure increase on a pipeline segment containing ERW pipe or pipe
with other specified seam issues.13 CenterPoint explained that it had intended to include the TFI
tool option only for manufacturing defects, not seam threats.14 Respondent further explained
that in spite of such mistake in its procedures, it never actually used a TFI tool in response to a
pressure increase15 and that after the OPS inspection, it revised its procedures to address this
issue. A TFI tool would not properly address the threat and could subsequently lead to a pipeline
12 ASME STANDARD B31.8S-2004, supra, § A4, “MANUFACTURING THREAT (PIPE SEAM AND PIPE).”
13 Response at 21; Closing at 8.
14 Id.
15 Id.



7
failure affecting public safety. Although CenterPoint notes that it revised its procedures, this
modification occurred after the OPS inspection and therefore does not cure the violation.
Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49
C.F.R. § 192.917(e)(4) by failing to select a proper assessment technology with a proven
application capable of assessing seam integrity and seam corrosion anomalies.
Item 6: The Notice alleged that Respondent violated 49 C.F.R. § 192.925(b)(1), which states:
§ 192.925 What are the requirements for using External Corrosion
Direct Assessment (ECDA)?
(a) Definition. ECDA is a four-step process that combines
preassessment, indirect inspection, direct examination, and post
assessment to evaluate the threat of external corrosion to the integrity of a
pipeline.
(b) General requirements. An operator that uses direct assessment to
assess the threat of external corrosion must follow the requirements in this
section, in ASME/ANSI B31.8S (incorporated by reference, see §192.7),
section 6.4, and in NACE RP 0502–2002 (incorporated by reference, see
§192.7). An operator must develop and implement a direct assessment
plan that has procedures addressing preassessment, indirect examination,
direct examination, and post-assessment. If the ECDA detects pipeline
coating damage, the operator must also integrate the data from the ECDA
with other information from the data integration (§192.917(b)) to evaluate
the covered segment for the threat of third party damage, and to address
the threat as required by § 192.917(e)(1).
(1) Preassessment. In addition to the requirements in ASME/ANSI
B31.8S section 6.4 and NACE RP 0502–2002, section 3, the plan's
procedures for preassessment must include—
(i) Provisions for applying more restrictive criteria when conducting
ECDA for the first time on a covered segment; and
(ii) The basis on which an operator selects at least two different, but
complementary indirect assessment tools to assess each ECDA Region. If
an operator utilizes an indirect inspection method that is not discussed in
Appendix A of NACE RP0502–2002, the operator must demonstrate the
applicability, validation basis, equipment used, application procedure, and
utilization of data for the inspection method.
The Notice alleged that Respondent violated 49 C.F.R. § 192.925(b)(1) by failing to comply with
its own procedures and the requirements of NACE RP 0502-2003 (NACE Standard), Section 3,
in conducting ECDA preassessments. Specifically, it alleged four separate violations of
§ 192.925(b)(1). First, it alleged that CenterPoint violated the NACE Standard and its own
procedures by failing to define minimum data collection requirements for conducting
16
preassessments.
Second, it alleged that the company violated the NACE Standard and its own
16 NACE Standard Section 3.2.1.1 provides: “The pipeline operator shall define minimum data requirements based
on the history and condition of the pipeline segment. In addition, the pipeline operator shall identify data elements
that are critical to the success of the ECDA process.”



8
procedures by failing to document the basis for the conservative assumptions used on the ALE,
BT-1 and A-206 pipelines.
17 Third, the Notice alleged that CenterPoint violated the NACE
Standard and its own procedures by failing to document whether an ECDA feasibility assessment
had been conducted.
18 Finally, it alleged that Respondent violated the NACE Standard and its
own procedures by failing to document either the specific indirect inspection tools that were
ultimately chosen or the basis for choosing them.
19
Regarding the first allegation, CenterPoint argued that it had collected adequate data to make an
ECDA feasibility determination.20 However, Respondent admitted that its procedures “did not
include a list of minimum data requirements defining when ECDA was a feasible
violated 49 C.F.R. § 192.925(b)(1) by failing to define minimum data requirements concerning
data collection for ECDA preassessments.
alternative…”21 Accordingly, upon a review of all of the evidence, I find that Respondent
Regarding the second allegation, CenterPoint argued that there is no requirement in
§ 192.925(b)(1) to document conservative assumptions.22 I disagree. Respondent’s own
procedures allowed the use of conservative assumptions and required that they be documented.23
Nonetheless, CenterPoint explained that no conservative assumptions were documented because
none were used on the ALE, BT-1, and A-206 pipelines.24 Accordingly, based on a review of
the record, I hereby order that this portion of Item 6 be withdrawn.
Regarding the third allegation, Respondent argued that it had performed an ECDA feasibility
assessment on the ALE, BT-1 and A-206 pipelines.25 The company explained that it had
recorded data on preassessment forms but admitted that its ECDA feasibility determination was
not recorded.26
CenterPoint further argued that its documentation of ECDA regions and tool
17 Respondent’s ECDA Procedure PS-03-01-232 states that conservative defaults may be substituted when data is
missing. Its Quality Assurance Procedure PS-03-01-268 requires the company to “verify that conservative
assumptions were documented.”
18 NACE Standard Section 3.3.1 provides: “The pipeline operator shall integrate and analyze the data collected [as
required in Section 3.2] to determine whether conditions for which indirect inspection tools cannot be used or that
would preclude ECDA application exist.”
19 The Notice also alleged that Respondent failed to document whether the assessment tools were complementary to
each other. Proper documentation of the basis for tool selection would invariably include information on whether
the tools were complementary. Therefore I do not treat the language in the Notice on complementary tools as a
separate allegation.
20 Response at 27-28.
21 Id.
22 Id. at 28.
23 See supra note 13.
24 Response at 28.
25 Id. at 29-30.
26 Id. at 30.



9
By failing to document the process it used to undertake a feasibility determination, Respondent
skipped a key step in the ECDA process. Without such documentation, neither Respondent nor
OPS can accurately determine whether the ECDA process was properly performed.
Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49
C.F.R. § 192.925(b)(1) by failing to properly document a feasibility assessment for the ALE,
BT-1 and A-206 pipelines.
selections proved that it had in fact performed a feasibility determination.27 Again, I disagree.
Regarding the fourth allegation, CenterPoint contended that it did document the specific indirect
inspection tools selected for the BT-1, ALE, and A-206 pipelines.
28 The regulation requires an
operator, as part of its preassessment procedure, to include “the basis on which an operator
selects at least two different, but complementary indirect assessment tools to assess each ECDA
region.” In addition, the publicly available 2004 OPS IMP Inspection Protocols indicated that
on when certain tools should be used, none of these documents explains the basis on which
Respondent nor OPS can verify that the proper tools were selected. Accordingly, based upon a
review of all of the evidence, I find that Respondent violated 49 C.F.R. § 192.925(b)(1) by
OPS would verify an operator’s documentation of its ECDA tool selections.29 While
CenterPoint has provided documents showing which tools it selected, as well as general guidance
specific tools were selected for particular ECDA regions. Absent such documentation, neither
failing to document the basis for its selection of indirect inspection tools.
Item 7: The Notice alleged that Respondent violated 49 C.F.R. § 192.925(b)(1)(i), as quoted
above, and § 192.925(b)(2)(i) and (b)(3)(i), which state:
§ 192.925 What are the requirements for using External Corrosion
Direct Assessment (ECDA)?
(a-b) ….
(2) Indirect examination. In addition to the requirements in
ASME/ANSI B31.8S section 6.4 and NACE RP 0502–2002, section 4, the
plan's procedures for indirect examination of the ECDA regions must
include—
(i) Provisions for applying more restrictive criteria when conducting
ECDA for the first time on a covered segment;…
(3) Direct examination. In addition to the requirements in
ASME/ANSI B31.8S section 6.4 and NACE RP 0502–2002, section 5, the
plan's procedures for direct examination of indications from the indirect
examination must include—
(i) Provisions for applying more restrictive criteria when conducting
ECDA for the first time on a covered segment;…
The Notice alleged that Respondent violated 49 C.F.R. § 192.925(b)(1)(i), (b)(2)(i) and (b)(3)(i)
by failing to document how it applied more restrictive criteria when conducting ECDA for the
27 Id.
28 Response at 31, Attachments 6.1–6.3 ECDA Preassessment Forms.
29 PHMSA-OPS Gas Integrity Management Protocol Results Form, Protocol D.02.c, (Oct. 2004) (available at
http://primis.phmsa.dot.gov/gasimp/documents.htm).



10
first time on a covered segment. The cited regulations impose restrictive criteria requirements at
the preassessment, indirect examination, and direct examination steps of the ECDA process.
Specifically, the Notice alleged that the ECDA assessments for the ALE, BT-1, and A-206
pipelines did not contain any documentation of the more restrictive criteria that CenterPoint used
for this initial ECDA.
Respondent contested this allegation and provided documents to demonstrate that it had, in fact,
this documentation and agrees that it demonstrates more restrictive criteria were in fact used and
properly documented. Accordingly, based on the foregoing and a review of the record, I order
that Item 7 be withdrawn.
documented its use of more restrictive criteria at the time of the inspection.30 OPS has reviewed
Item 8: The Notice alleged that Respondent violated 49 C.F.R. § 192.927(c)(1)(i), which states:
§ 192.927 What are the requirements for using Internal Corrosion
Direct Assessment (ICDA)?
(a) ….
(c) The ICDA plan. An operator must develop and follow an ICDA
plan that provides for preassessment, identification of ICDA regions and
excavation locations, detailed examination of pipe at excavation locations,
and post-assessment evaluation and monitoring.
(1) Preassessment. In the preassessment stage, an operator must gather
and integrate data and information needed to evaluate the feasibility of
ICDA for the covered segment, and to support use of a model to identify
the locations along the pipe segment where electrolyte may accumulate, to
identify ICDA regions, and to identify areas within the covered segment
where liquids may potentially be entrained. This data and information
includes, but is not limited to—
(i) All data elements listed in appendix A2 of ASME/ANSI B31.8S;…
The Notice alleged that Respondent violated 49 C.F.R. § 192.927(c)(1)(i) by failing to evaluate
the feasibility of ICDA for certain pipeline segments. Specifically, it alleged that CenterPoint
failed to perform or document feasibility evaluations for ICDA preassessments performed on its
FT-11 and ADT-8 pipelines. It also alleged that Respondent did not document the basis for
selecting the feasibility criteria for pigging, water upsets, and introduction of sludge. The Notice
further alleged that Respondent’s ICDA preassessment data for these pipelines was of “poor
quality” and that this “could lead” to improper determinations of ICDA regions.
CenterPoint argued that it had, in fact, performed and documented feasibility evaluations and
feasibility flow charts for the FT-11 and ADT-8 pipelines, and that it had records of the source
data used to fill out the charts.
31 The company also pointed to those portions of its IMP
procedures that described the basis for selecting feasibility criteria.32
In response, OPS argued
30 Response at 32-35, Attachments 7.2-7.16
31 Response at 37, Attachments 8.1-8.2 and 8.5-8.12.
32 Id., Attachment 8.4, Procedure 03-01-238.



11
that the flow charts did not constitute the evaluation required by the regulation but the agency did
not explain why. While the feasibility flow charts are indeed sparse, they do show that
Respondent performed some type of feasibility analysis. In the absence of more specific
allegations or some explanation as to why Respondent’s documentation was inadequate, I find
that the record does not support a finding of violation for this portion of the allegation.
Finally, Respondent argued that it had the necessary data to perform ICDA preassessments and
that it was not of “poor quality”
.
33 Respondent provided numerous examples of such data.34
Again, the Notice did not explain why CenterPoint’s data was of poor quality or what data was
missing. With such lack of specificity in the Notice and upon review of the documents provided
by Respondent and which OPS has not addressed, I find that the record does not support a
finding of violation on this portion of the allegation.
Accordingly, based on the foregoing and a review of the record, I order that Item 8 be
withdrawn.
Item 9: The Notice alleged that Respondent violated 49 C.F.R. § 192.927(c)(5)(ii), which states:
§ 192.927 What are the requirements for using Internal Corrosion
Direct Assessment (ICDA)?
(a) ….
(c) The ICDA plan. An operator must develop and follow an ICDA
plan that provides for preassessment, identification of ICDA regions and
excavation locations, detailed examination of pipe at excavation locations,
and post-assessment evaluation and monitoring.
(1) ….
(5) Other requirements. The ICDA plan must also include–
(i) ….
(ii) Provisions for apply more restrictive criteria when conducting
ICDA for the first time on a covered segment and that become less
stringent as the operator gains experience;…
The Notice alleged that Respondent violated 49 C.F.R. § 192.927(c)(5)(ii) by failing to
document the more restrictive criteria the company used when conducting ICDA for the first
time on a covered segment. Specifically, it alleged that CenterPoint failed to document these
criteria, both in its ICDA plan and in the initial ICDAs performed on the FT-11 and ADT-8
pipelines. Respondent contested this allegation and provided numerous documents to
demonstrate that it had in fact documented more restrictive criteria at the time of the
inspection.35
OPS has reviewed these materials and agrees that CenterPoint was in compliance with this
regulation at the time of the inspection. Accordingly, based upon the foregoing and a review of
the record, I order that Item 9 be withdrawn.
33 Response at 38-39.
34 Response, Attachments 8.13-8.26.
35 Response at 41-43, Attachments 9.1-9.8.



12
Item 10: The Notice alleged that Respondent violated 49 C.F.R. § 192.929(b)(1), which states:
§ 192.929 What are the requirements for using Direct Assessment for
Stress Corrosion Cracking (SCCDA)?
(a) ….
(b) General requirements. An operator using direct assessment as an
integrity assessment method to address stress corrosion cracking in a
covered pipeline segment must have a plan that provides, at minimum,
for—
(1) Data gathering and integration. An operator's plan must provide
for a systematic process to collect and evaluate data for all covered
segments to identify whether the conditions for SCC are present and to
prioritize the covered segments for assessment. This process must include
gathering and evaluating data related to SCC at all sites an operator
excavates during the conduct of its pipeline operations where the criteria
in ASME/ANSI B31.8S (incorporated by reference, see §192.7), appendix
A3.3 indicate the potential for SCC. This data includes at minimum, the
data specified in ASME/ANSI B31.8S, appendix A3.
The Notice alleged that Respondent violated 49 C.F.R. § 192.929(b)(1) by failing to provide in
its IMP a systematic data collection and evaluation process for all covered pipeline segments.
Specifically, the Notice alleged four separate violations regarding the SCCDA portion of
CenterPoint’s IMP.
First, it alleged that Respondent failed to include in its SCCDA plan a requirement for the
gathering and integration of data related to SCC at all sites. Specifically, it alleged that
CenterPoint excavated both covered and non-covered pipe segments, during its normal course of
business, in a manner that met the criteria listed in the ASME Standard indicating potential SCC.
The company’s procedures, however, allegedly failed to require the collection of data on non-
covered pipelines, as required by the regulation. Second, it alleged that Respondent failed to
follow its own procedures by not gathering and reviewing certain data elements used for SCCDA
under the ASME Standard. Third, it alleged that Respondent failed to follow the ASME
Standard by including a provision in its IMP for notifying PHMSA at least 180 days prior to
using a “near-neutral” SCCDA plan. Fourth, it alleged that Respondent failed to follow the
ASME Standard by neglecting to include a provision in its IMP requiring the performance of a
hydrostatic “spike test” following an in-service leak or rupture attributable to SCC.
Regarding the first allegation, Respondent argued that it had performed and documented
inspections of its pipelines during excavation and that its procedures for doing so were contained
in its Operations and Maintenance (O&M) manual, rather than in its IMP documentation.36
However, Respondent admitted that “its procedures at the time of the audit did not specifically
call for evaluation of data at sites where criteria indicate the potential for SCC.”37
Accordingly,
based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R.
§ 192.929(b)(1) by failing to include in its SCCDA plan a requirement for the gathering and
integration of data related to SCC at all excavation sites where the criteria listed in the ASME
36 Response at 46.
37 Id. at 47.



13
Standard indicated the potential for SCC.
Regarding the second allegation, Respondent argued that it had, in fact, evaluated the SCCDA-
related data as required by its procedures; the company submitted Data Element Forms to
support its position.
that Respondent performed the requisite evaluations as of the date of the inspection.
Accordingly, based on the foregoing and a review of the record, I order that this portion of Item
10 be withdrawn.
38 Upon review of these records, I find that these materials do demonstrate
Regarding the third allegation, Respondent argued that its IMP procedure need not contain a
provision for notifying PHMSA before using its near-neutral SCCDA plan. CenterPoint argued
because § 192.921 allows for the use of direct assessment to address SCC, the near-neutral
version of direct assessment technology cannot be considered an “Other Technology” for which
it would have to give notice under §192.921(a)(4).39 Respondent also cited several PHMSA
“Frequently Asked Questions” (FAQs) on Gas IMP for the proposition that these materials were
that it was reasonable to conclude that it did not need to make an “Other Technology”
notification to implement its near-neutral variant of SCCDA.
internally inconsistent, and in conflict with the regulation.40 On that basis, CenterPoint argued
Respondent’s argument, however, does not reflect the different assessment tools that can be used
to satisfy the complex, performance-based Gas IMP requirements. Respondent lumps all
SCCDA together when reaching its conclusion. Section A3 of the ASME Standard and GAS
IMP FAQs distinguish between different kinds of SCCDA. The ASME Standard applies to
high-pH SCCDA, not near-neutral SCCDA.
41 The only FAQ that specifically mentions near-
neutral SCCDA indicates that it is considered an “Other Technology,” for which notification is
required.42
While Section 192.921(a) does permit SCCDA as an assessment tool, it must be read in
combination with Section 3 of the ASME Standard, which applies only to high-pH SCCDA.
Therefore, near-neutral SCCDA presents a distinct set of issues. It is this distinction that led the
drafters of FAQ 223 to note that near-neutral SCC is considered “Other Technology.”
Accordingly, based on the foregoing and a review of the record, I find that Respondent violated
49 C.F.R. § 192.929(b)(1) by failing to include a provision in its IMP for notifying PHMSA 180
days before proposing to use its near-neutral SCCDA plan.
Regarding the fourth allegation, Respondent argued that its procedures were, in fact, consistent
with the requirements in the ASME Standard for hydrotesting a pipeline after an in-service leak
or rupture attributable to SCC. CenterPoint contended that the ASME Standard does not use the
phrase “spike test” that was mentioned in the Notice and that OPS had misinterpreted the intent
38 Id. at 48, Attachments 10.4-10.15.
39 Id. at 50.
40 Id. at 51, citing FAQs 40, 46, 97, and 223. The PHMSA Gas IMP FAQs are available online at:
http://primis.phmsa.dot.gov/gasimp/faqlist.gim (last accessed September 16, 2010).
41 ASME B31.8S, Section A3.1.
42 FAQ #223.



14
of the company’s procedures. I agree. Respondent’s procedures in place at the time of the
inspection were consistent with Appendix A3.4b of the ASME Standard. Accordingly, based on
the foregoing and a review of the record, I order that this portion of Item 10 be withdrawn.
Item 11: The Notice alleged that Respondent violated 49 C.F.R. § 192.935(c), which states:
§ 192.935 What additional preventative and mitigative measures
must an operator take?
(a) ….
(c) Automatic shut-off valves (ASV) or Remote control valves (RCV).
If an operator determines, based on a risk analysis, that an ASV or RCV
would be an efficient means of adding protection to a high consequence
area in the event of a gas release, an operator must install the ASV or
RCV. In making that determination, an operator must, at least, consider
the following factors—swiftness of leak detection and pipe shutdown
capabilities, the type of gas being transported, operating pressure, the rate
of potential release, pipeline profile, the potential for ignition, and location
of nearest response personnel.
The Notice alleged that Respondent violated 49 C.F.R. § 192.935(c) and its own procedures by
failing to perform a risk analysis to determine whether either ASVs or RCVs would be efficient
means of adding protection for HCAs in the event of a gas release. CenterPoint argued that it
had, in fact, performed such an analysis and submitted documentation in support of its position.43
These materials support Respondent’s argument. Accordingly, based on the foregoing and a
review of the record, I order that Item 11 be withdrawn.
These findings of violation will be considered prior offenses in any subsequent enforcement
action taken against Respondent.
Additional Issues
In its Response, CenterPoint argued that PHMSA lacked the authority to impose a civil penalty
for the alleged violations in this case.44 After the hearing, Respondent withdrew this argument.45
Respondent also argued that OPS should have addressed the issues in this case through a Notice
of Amendment (NOA), rather than a Notice of Probable Violation. CenterPoint argued that
because it was at an early stage of the implementation of its IMP program, an NOA would have
been the appropriate enforcement mechanism. I disagree. There are no statutory or regulatory
requirements that OPS use a particular tool in particular circumstances. The choice of
enforcement tools resides uniquely with the agency. In this particular case, I do not believe that
the agency abused its discretion or violated any regulation in choosing to issue a Notice of
Probable Violation, as opposed to an NOA or other enforcement tool.
43 Response at 55-56.
44 Response at 1.
45 Closing at 2.



15
ASSESSMENT OF PENALTY
Under 49 U.S.C. § 60122 and 49 C.F.R. § 190.225, in determining the amount of the civil
penalty, I must consider the following criteria: the nature, circumstances, and gravity of the
violation, including adverse impact on the environment; the degree of Respondent’s culpability;
the history of Respondent’s prior offenses; the Respondent’s ability to pay the penalty and any
effect that the penalty may have on its ability to continue doing business; and the good faith of
Respondent in attempting to comply with the pipeline safety regulations. In addition, I may
consider the economic benefit gained from the violation without any reduction because of
subsequent damages, and such other matters as justice may require.
The Notice proposed a total civil penalty of $95,000 for violations of §§ 192.917(a), (c), (e)(1),
(e)(4), and 192.925(b)(1). Having withdrawn the allegations of violation for Items 4 and 7, no
civil penalty is appropriate for those items.
Item 1: The Notice proposed a civil penalty of $17,000, for Respondent’s failure to properly
evaluate in its IMP the potential for interactive threats for each covered pipeline segment. In its
Closing, Respondent argued that the penalty should be withdrawn or substantially reduced due to
the relatively minor gravity of the alleged violation. The company contended that the violation
was not serious because its risk model had demonstrated that those pipeline segments were
accurately prioritized for assessment. CenterPoint also argued that it was not culpable for a
violation because it was not required to use a “plus” factor for interactive threats, that it had
made a good-faith effort to comply with the regulation, and that it had not incurred any economic
benefit as a result of the violation.
Although it appears that the deficiencies in Respondent’s risk model have not led to any pipeline
incidents, the company is nonetheless responsible for accurately addressing the potential for
interactive threats on each covered pipeline segment. CenterPoint did not do this. The
regulations do not require a specific “plus” factor but, rather, an analysis that accounts for the
interactive nature of threats, i.e., that accounts for a combination of threats resulting in a greater
risk than each threat considered individually. Absent such a type of analysis, CenterPoint may
miss critical information on the safety of its pipeline facilities.
As for the company’s good faith argument, the proposed penalty amount did take into account
the company’s overall IMP compliance efforts and the less severe nature of the violation.
Furthermore, the amount is far below the $100,000 per violation per day limit on administrative
penalties. Finally, the proposed penalty amount did not include an economic-benefit component.
Accordingly, having reviewed the record and considered the assessment criteria, I assess
Respondent a civil penalty of $17,000.
Item 2: The Notice proposed a civil penalty of $17,000, for Respondent’s failure to provide
documentation in its IMP to support the conclusion to eliminate certain threats from its risk
assessment for HCAs. In its Closing, Respondent again argued that this penalty should be
withdrawn or substantially reduced due to the relatively minor gravity of the alleged violation.
The company contended that the violation was not serious because its experience had shown that
its risk model accurately prioritized those pipeline segments for assessment. CenterPoint also



16
argued that it was not culpable for the violation because its procedures explained when threats
would be eliminated, that it had acted in good faith to comply with the regulations, and that it
had not incurred any economic benefit as a result of the violation.
As discussed above, Respondent provided no documentation of the application of its risk
assessment to the actual pipeline system data. Therefore, neither Respondent nor OPS could
determine if the company’s decisions to eliminate threats from HCAs were appropriate. Absent
such documentation, potential errors in threat elimination may go unnoticed and ultimately
undermine pipeline safety. As discussed in Item 1 above, the proposed penalty amount did take
into account the company’s overall IMP compliance efforts, the less severe nature of the
violation, and lack of economic benefit. Accordingly, having reviewed the record and
considered the assessment criteria, I assess Respondent a civil penalty of $17,000.
Item 5: The Notice proposed a civil penalty of $17,000, for Respondent’s failure to select an
assessment technology capable of assessing seam integrity and seam corrosion anomalies for
covered segments containing ERW or similar pipe segments that had experienced seam failure or
pressure exceeding maximum operating pressure in the last five years. In its Closing,
Respondent argued that this penalty should be withdrawn or substantially reduced. Again,
CenterPoint argued that this violation was not serious because it simply constituted an error in its
procedures and that it had never actually used the incorrect technology for assessing seam
integrity. The company argued that it was not culpable, had acted in good faith to comply, and
that it had not derived any economic benefit from the violation. Although, Respondent’s error
did not result in any damage to the pipeline system or the environment, accurate procedures are
important to pipeline safety. By including a technology that would not properly address the
specific threat, Respondent ran the risk of using the wrong diagnostic tool on its pipeline system.
This error could have undermined pipeline safety.
The relatively modest proposed penalty amount reflects Respondent’s acknowledged efforts to
comply and the less severe nature of the violation. Furthermore, the amount is far below the
$100,000 per violation per day limit on administrative penalties. Finally, the proposed penalty
amount did not contain an economic benefit component. Accordingly, having reviewed the
record and considered the assessment criteria, I assess Respondent a civil penalty of $17,000.
In summary, having reviewed the record and considered the assessment criteria for all the Items
discussed above, I assess Respondent a reduced total civil penalty of $51,000.
Payment of the civil penalty must be made within 20 days of service. Federal regulations
(49 C.F.R. § 89.21(b)(3)) require such payment to be made by wire transfer through the Federal
Reserve Communications System (Fedwire), to the account of the U.S. Treasury. Detailed
instructions are contained in the enclosure. Questions concerning wire transfers should be
directed to: Financial Operations Division (AMZ-341), Federal Aviation Administration, Mike
Monroney Aeronautical Center, P.O. Box 269039, Oklahoma City, Oklahoma 73125. The
Financial Operations Division telephone number is (405) 954-8893.
Failure to pay the $51,000 civil penalty will result in accrual of interest at the current annual rate
in accordance with 31 U.S.C. § 3717, 31 C.F.R. § 901.9 and 49 C.F.R. § 89.23. Pursuant to



17
those same authorities, a late penalty charge of six percent (6%) per annum will be charged if
payment is not made within 110 days of service. Furthermore, failure to pay the civil penalty
may result in referral of the matter to the Attorney General for appropriate action in a United
States District Court.
COMPLIANCE ORDER
The Notice proposed a compliance order with respect to Items 1 through 11 in the Notice for
violations of 49 C.F.R. §§ 192.917(a), 192.917(c), 192.917(e)(1), 192.917(e)(4), 192.925(b)(1),
192.927(c)(1)(i), 192.927(c)(5)(ii), 192.929(b)(1), and 192.935(c). I have withdrawn several of
these items. In addition, the Director has indicated that Respondent has taken action to address
some of the cited violations. The remaining compliance order requirements are set out below.
Under 49 U.S.C. § 60118(a), each person who engages in the transportation of gas or who owns
or operates a pipeline facility is required to comply with the applicable safety standards
established under chapter 601. Pursuant to the authority of 49 U.S.C. § 60118(b) and 49 C.F.R.
§ 190.217, Respondent is ordered to take the following actions to ensure compliance with the
pipeline safety regulations applicable to its operations. Respondent shall:
1. With respect to the violation of § 192.917(a) (Item 1), Respondent must
implement its PS-03-01-216 procedure and develop and implement a
process to ensure that the evaluation of interactive threats is addressed.
CenterPoint must provide an evaluation of interactive threats for all
covered segments.
2. With respect to the violation of § 192.917(c) (Item 2), Respondent must
modify its IMP procedures to include a process to document any decisions
to eliminate certain threats from its risk assessments. Such documentation
shall clearly set out the basis for any decision to eliminate threats. Within
90 days of receipt of this Final Order, Respondent must modify its IMP
procedures, develop and implement such process, and submit
documentation of compliance with this item.
3. With respect to the violation of § 192.929(b)(1) (Item 10), Respondent
must modify its IMP procedures to include a provision for notifying
PHMSA of its intent to use any “Other Technology,” whenever the
company plans to use its near-neutral SCCDA plan. Within 90 days of
receipt of this Final Order, Respondent must modify its IMP procedures,
develop and implement such provision, and submit documentation of
compliance with this item.
4. Respondent is requested to maintain documentation of the safety
improvement costs associated with fulfilling this Compliance Order and
submit the total to R.M. Seeley, Director, Southwest Region, PHMSA.
Costs shall be reported in two categories: 1) total cost associated with



18
preparation/revision of plans, procedures, studies and analyses, and 2)
total cost associated with replacements, additions and other changes to
pipeline infrastructure.
The Director may grant an extension of time to comply with any of the required items upon a
written request timely submitted by the Respondent demonstrating good cause for an extension.
The Director has indicated that Respondent has amended its IMP procedures to address certain of
the proposed compliance order terms. These actions satisfy the requirements in Items 3, 5 and 6
of the proposed compliance order.
Failure to comply with this Order may result in administrative assessment of civil penalties not
to exceed $100,000 for each violation for each day the violation continues or in referral to the
Attorney General for appropriate relief in a district court of the United States.
Under 49 C.F.R. § 190.215, Respondent has a right to submit a Petition for Reconsideration of
this Final Order. The petition must be sent to: Associate Administrator, Office of Pipeline
Safety, PHMSA, 1200 New Jersey Avenue, SE, East Building, 2nd Floor, Washington, DC
20590, with a copy sent to the Office of Chief Counsel, PHMSA, at the same address. PHMSA
will accept petitions received no later than 20 days after receipt of service of this Final Order by
the Respondent, provided they contain a brief statement of the issue(s) and meet all other
requirements of 49 C.F.R. § 190.215. The filing of a petition automatically stays the payment of
any civil penalty assessed. Unless the Associate Administrator, upon request, grants a stay, all
other terms and conditions of this Final Order are effective upon service in accordance with 49
C.F.R. § 190.5.
___________________________________ __________________________
Jeffrey D. Wiese Date Issued
Associate Administrator
for Pipeline Safety

420071004_Notice Letter_03292007.pdf

@
U.S. Deportment
of Tronsportotlon
Plpeline qnd
Hozordous rtioterlols sofely
AdmlnBlrotlon
8701 South Gessnel, Suite 1110
Houston, TX 77074
NOTICE OF PROBABLE VIOLATION,
PROPOSED CIVIL PENALW
and
PROPOSED COMPLIANCE ORDER
CERTIFIED MAIL. RETURN RECEIPT REQUESTED
March 29, 2007
Walter Ferguson,
Senior V.P and C.O.O. Pipeline Services
CenterPoint Energy Gas Transmission
525 Milam
Shreveport, LA 71101
cPF 4-2007-1004
Dear Mr. Ferguson:
Duringtheweeksof September 12-16, and Novemberl4-18,2005, representativesof the
Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of
49 United States Code inspected your integrity management program in Shreveport, Louisiana.
As a result of the inspection, it appears that you have committed probable violations of the
Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and
the orobable violations are:
1. S 192.917 How does an operator identify potential threats to pipeline integrity and
use the threat identification in its integrity program?
(a) Threat identification. An operator must identify and evaluate all potential
threats to each covered pipeline segment. Potential threats that an operator must
consider include, but are not limited to, the threats listed in ASME/ANSI 831.8S
(ibr, see 5192.7), section 2, which are as follows:



Department of Transportation
Pipeline and Hazardous Materials Safety Administration
Gompliance Registry: Anitra Brown
4OO 7'n Street, SW
Room 2103
Washington, DC 20590



2.
3.
(1) Time dependent threats such as internal corrosion, external corrosion, and
stress corrosion cracking;
(2) Static or resident threats, such as fabrication or construction defects;
(3) Time independent threats such as third party damage and outside force
damage; and
(4) Human error.
CenterPoint Energy Gas Transmission (CE) did not identify or evaluate the potential for
interactive threats to each covered pipeline segment. The regulation specifically
requires that CE identify and evaluate the threats listed in ASME/ANSI 831.85, section
2, which includes the following:
ASME 83'1 .85 2.2Integrity Threat Classification
The interactive nature of threats (i.e., more than one threat occurring on a section
of pipeline at the same time) shall also be considered. An example of such an
interaction is corrosion at a location that also has third party damage.
While CE's procedure PS-03-01-216, "Threat ldentification and Risk Assessment,"
Section 2.2 states that, "The results from the evaluation together with the criteria used to
evaluate the significance of this threat or interaction of threats to the covered pipe
segment shall be used to prioritize the integrity assessment," there is not a process to
ensure the evaluation of interactive threats is accomolished.
S 192.917 (see above)
(c) Risk assessment. An operator must conduct a risk assessment that follows
ASME/ANSI 831.8S, section 5, and considers the identified threats for each
covered segment.
CE did not provide specific documentation requirements or documentation to support
conclusions to eliminate threats from HCAs in accordance with the minimum
requirements specified by each of the relevant sections of ASME 831.8S. At the time of
the inspection, CE did not provide the inspection team with any documentation in
support of this requirement. The regulations require that threats be identified and that a
risk assessment based on those threats be oerformed accordinq to section 5 of ASME
831.85.
S 192.917 (see above)
(e) Actions to address particular threats. lf an operator identifies any of the
following threats, the operator must take the following actions to address the
threat.
(1) Third pafi damage. An operator must utilize the data integration required in
paragraph (b) of this section and ASME/ ANSI 831.8S, Appendix A7 to determine
the susceptibility of each covered segment to the threat of third party damage. lf
an operator identifies the threat of third party damage, the operator must
implement comprehensive additional preventive measures in accordance with
5192.935 and monitorthe effectiveness of the preventive measures. lf, in



4.
5.
conducting a baseline assessment under $192.921, or a reassessment under
5192.937, an operator uses an internal inspection tool or external corrosion direct
assessment, the operator must integrate data from these assessments with data
related to any encroachment or foreign line crossing on the covered segment, to
define where potential indications of third party damage may exist in the covered
segment. An operator must also have procedures in its integrity management
program addressing actions it will take to respond to findings from this data
integration.
CE does not have a formal procedure or process by which it integrates inspection tool or
external corrosion direct assessment data with data related to encroachments or foreign
line crossings to define where potential indications of third party damage may exist in
covered sections. CE procedures PS-03-01-1 10, "Gather, Review, and Integrate Data,"
and section 2.4 of PS-03-01-216, "Threat ldentification and Risk Assessment," describe
the collection and evaluation of data for the risk analysis. However, neither procedure
describes requirements for data integration of lLl and ECDA data with data related to
encroachments of foreign line crossings prior to any post assessment review.
Addltionally, the inspection team did not identify any evidence that this data integration
had been performed.
S 192.917 (e)(1) (see above)
CE did not integrate ECDA and lLl data with data related to encroachment and foreign
line crossing data to evaluate the covered segment for the threat of third party damage.
CE procedures PS-03-01-232, "External Corrosion Direct Assessment," and PS-03-01-
230, "Direct Assessment Plan," describe how ECDA assessments are to be conducted,
the data to be collected, and what documentation needs to be retained. PS-03-01-268,
"lMP Quality Assurance", Appendix A requires that the data elements used for ECDA be
gathered and integrated. These plans and procedures reference the NACE RP 0502-
2002 ECDA assessment standard but do not reference the need to integrate
encroachment and foreign line data as required in $192.917 (eX1) and $192.925 (b) for
Pre-assessments, Indirect Inspections and Direct Examinations undertaken on ECDA for
a region or a segment. Three ECDA assessments were reviewed (line ALE, line BT-1
,
and 4-206); and in each case, there was no documentation that this data integration was
performed.
S 192.917 (e) (see above)
(4) ERW pipe. lf a covered pipeline segment contains low frequency electric
resistance welded pipe (ERW), lap welded pipe or other pipe that satisties the
conditions specified in ASME/ANSI 831 ,8 S, Appendices A4.3 and A4.4, and any
covered or non covered segment in the pipeline system with such pipe has
experienced seam failure, or operating pressure on the covered segment has
increased over the maximum operating pressure experienced during the
preceding five years, an operator must select an assessment technology or
technologies with a proven application capable of assessing seam integrity and
seam corrosion anomalies. The operator must prioritize the covered segment as a
high risk segment for the baseline assessment or a subsequent reassessment.



CE's Baseline Assessment Plan (BAP) did not consistently specify an assessment
method(s) for each covered segment that is appropriate for identifying anomalies
associated with specific threats identified for the segment. The rule requires that an
operator must select an assessment technology or technologies with a proven
application capable of assessing seam integrity and seam corrosion anomalies. Further,
ASME B31.8S states in section A4, "Manufacturing Threat (Pipe Seam and Pipe), A4.4
Integrity Assessment," "...pressure testing must be performed to address the seam
issue." CE allows for either a Hydrotest or the use of TFI based on their "BAP - Integrity
Assessment Selection Guide." However, according to ASME 831 .85, a TFI tool is not
an acceptable method of integrity assessment for this threat. CE describes the various
assessment methods in PS-03-01-224, "Assessment Methods Selection Process" which
references CE's, "BAP - Integrity Assessment Selection Guide." The assessment path
on the flow chart in the Guide allows for a hydrotest, pipe replacement, or use of a TFI
tool. The ASME 831.8S guidance states that only a hydrotest is appropriate. A pipe
replacement is an acceptable approach to eliminate the seam integrity threat, but for
those instances where CE does not elect to replace the pipe, only the performance of a
hydrotest would satisfy the requirements of the rule and the ASME guidance document.
S 192.925 What are the requirements for using External Corrosion Direct
Assessment (ECDA)?
(b) General requirements. An operator that uses direct assessment to assess the
threat of external corrosion must follow the requirements in this section, in
ASME/ANSI 831.8S (ibr, see 5192.7), section 6.4, and in NAGE RP 0502-2002 (ibr,
see $192.7). An operator must develop and implement a direct assessment plan
that has procedures addressing preassessment, indirect examination, direct
examination, and post-assessment. lf the EGDA detects pipeline coating damage,
the operator must also integrate the data from the EGDA with other information
from the data integration ($192.917(b)) to evaluate the covered segment for the
threat of third party damage, and to address the threat as required by
$1e2.e17(e)(1).
(1) Preassessment. In addition to the requirements in ASME/ANSI 831.8S section
6.4 and NACE RP 0502-2002, section 3, ...
CE's plan did not adhere to the requirements of NACE RP 0502-2002, Section 3 by not
defining minimum data requirements. CE procedures PS-03-01-232, "External
Corrosion Direct Assessment," PS-03-0'1-230, "Direci Assessment Plan," and PS8'140
'ECDA Data Elements" describe what data elements should be considered to perform
an ECDA. However, the minimum data elements that are needed to determine if an
ECDA can be conducted are not documented as required by NACE RP 0502, Section
3.2.1.1 which states, "The pipeline operator shall define minimum data requirements
based on the history and condition of the pipeline segment. In addition, the pipeline
operator shall identify data elernents that are critical to the success of the ECDA
process."
CE's plan did not adhere to the requirements of NACE RP 0502-2002, Section 3 by not
documenting conservative assumptions. CE procedures allow conservative
assumptions be made where data is not available to address data sufficiency



7. requirements. Three ECDA assessments (completed through the third step, Direct
Examination, at the time of the inspection) were reviewed (lines ALE, BT-1
, and 4-206);
and in each case, there was no documentation on the minimum required data, what the
basis was for any of the conservative assumptions, and if the ECDA was feasible with
the data elements available. CE stated that they only have 10 years of data available for
integrity management but that additional historic data may be at field locations. Past
cathodic protection data is needed to determine if active corrosion is taking place or if
corrosion was the result of past inadequate cathodic protection. Under other sections of
$192, much of the cathodic protection data should have been retained for the life of the
pipeline and thus should be available for these ECDA purposes. NACE RP 0502,
Section 3.2.4 states, "ln the event that the pipeline operator determines that sufficient
data for some ECDA regions comprising a segment are not available or cannot be
collected to support the Pre-Assessment Step, ECDA shall not be used for those ECDA
regions."
CE's plan did not adhere to the requirements of their own procedures and NACE RP
0502-2002, Section 3 by not documenting that a feasibility assessment was undertaken.
CE procedures PS-03-01-232 S4.0, "External Corrosion Direct Assessment," PS-03-01-
230, "Direct Assessment Plan," and PS-03-01-268, "lMP Quality Assurance", Appendix
A require that the feasibility of each ECDA conducted be assessed and documented. ln
the three ECDAs reviewed by the inspection team (lines BT-1, ALE, and A-206) that CE
started and completed through the Direct Examination step, there was no documentation
that a feasibility assessment was undertaken. Documentation on what was considered
during the feasibility review is critical to determine the appiicability of the ECDA process
to other covered segments and for feedback as required by NACE RP 0502, 5192.925
and CE procedures PS-03-01-232, "External Corrosion Direct Assessment," and PS-03-
01-268, "lMP Quality Assurance", Appendix A.
CE's plan did not adhere to the requirements of their own procedures and NACE RP
0502-2002, Section 3 by not documenting the specific indirect inspections tools chosen
and if they were complementary to each other. CE procedures PS-03-01-232, "External
Corrosion Direct Assessment," PS-03-01-230, "Direct Assessment Plan," and PS-03-01-
268, "lMP Quality Assurance", Appendix A require that the indirect tool selection for each
ECDA conducted be verified and documented. In the three ECDAs reviewed by the
inspection team (lines BT-1, ALE, and 4-206), there was no documentation regarding
why the specific indirect inspections tools were chosen and if they were complementary
to each other. NACE RP 0502, Section 3.4.1.1 states, "The pipeline operator shall
select indirect inspection tools based on their ability to detect corrosion activity andlorl
coating holidays reliably under the specific pipeline conditions to be encountered."
NACE RP 0502, Section 3.4.1.2 states, "The pipeline operator should endeavor to select
indirect inspection tools that are complementary. That is, the operator should select
tools such that the strengths of one tool compensate for the limitations of another."
S 192.925 (b) (see above)
(1) Preassessment. In addition to the requirements in ASME/ANSI 831.8S section
6.4 and NACE RP 0502-2002, section 3, the plan's procedures for preassessment
must include-
i. Provisions for applying more restrictive criteria when conducting
EGDA for the first time on a covered segment;



(2) lndirect Examination. In addition to the requirements in ASME/ANSI 831.8S
section 6.4 and NACE RP 0502-2002, section 4, the plan's procedures for indirect
examination of the EGDA regions must include -
i. Provisions for applying more restrictive criteria when conducting
EGDA for the first time on a covered segment;
(b)(3) Direct Examination- In addition to the requirements in ASME/ANSI 831.8S
section 6.4 and NACE RP 0502-2002, section 5, the plan's procedures for direct
examination of indications from the indirect examination must include -
i. Provisions for applying more restrictive criteria when conducting
EGDA for the first time on a covered segment;
CE, in their ECDA plan, did not document the more restrictive criteria, as required by
S192.925, when they conducted ECDA for the first time on a covered segment. These
more restrictive criteria are for pre-assessment, indirect inspection, and direct
examination steps of the ECDA process. CE did not document for each specific
assessment how the more restrictive criteria were applied. CE procedures PS-03-01-
232,"External Corrosion Direct Assessment," and PS-03-01-230, "Direct Assessment
Plan," describe how ECDA assessments are to be conducted, the data to be collected
and what documentation needs to be retained. These plans and procedures reference
the NACE RP 0502-2002 ECDA assessment standard but do not reference the need to
document the more restrictive criteria as required in $192.925(bX1) subparts (i), (ii) and
(iii) for Pre-assessments, Indirect Inspections and Direct Examinations undertaken on an
initial ECDA on a region or a segment. Three ECDA assessments were reviewed by the
inspection team (line ALE, line BT-1, and A-206), and in each case there was no
documentation of the more restrictive criteria for this initial ECDA on these segments.
8. S 192.927 What are the requirements for using Internal Gorrosion Direct
Assessment (IGDA)?
(c) The ICDA plan. An operator must develop and follow an ICDA plan that
provides for preassessment, identification of IGDA regions and excavation
locations, detailed examination of pipe at excavation locations, and post-
assessment evaluation and monitoring.
(1) Preassessment. In the preassessment stage, an operator must gather and
integrate data and information needed to evaluate the feasibility of IGDA for the
covered segment, and to support use of a model to identify the locations along
the pipe segment where electrolyte may accumulate, to identify IGDA regions, and
to identify areas within the covered segment where liquids may potentially be
entrained. This data and information includes, but is not limited to .
i. All data elements listed in Appendix A2 of ASME/ANSI 831.8S;
CE's ICDA plan did not adhere to the requirements of their own procedures and
Appendix A2 of ASME/ANSI 831.8S. CE procedures PS-03-01-238, "Dry Gas - Intemal
Corrosion Direct Assessment," PS-03-01-230. "Direct Assessment Plan," and PS-03-01-
268, "lMP Quality Assurance", Appendix A require ICDA feasibility be performed in the
pre-assessment step; and no feasibility evaluation results were documented on the
ICDA pre-assessments performed on lines FT-l 1 and ADT-8 that were completed prior
to the inspection. CE did not document the results of the feasibility analysis, and there



was not sufficient evidence to conclude that the lines selected for ICDA met the ICDA
criteria. CE did not provide sufficient documentation to support the use of ICDA on the
lines reviewed. CE did nol document the basis for selecting the feasibility criteria for
pigging, water upsets, and introduction of sludge. In Figure 2, "DG-ICDA Feasibility
Filter'' of procedure PS-03-01-238, "Dry Gas - Internal Corrosion Direct Assessment,"
there are several numerical values for some of the feasibility issues, such as "Routine
pipeline pigging (more than 3 times per year)," etc. but there is no explanation on where
these values come from or how they are to be generated.
Based on a review during the inspection of the data elements for lines FT-'l 1 and ADT-8,
the data was of poor quality, and CE did not review the data as required in their
procedures. During the review of several ICDA pre-assessments, data quality was
determined to be poor or data was missing. CE procedures PS-03-01-238, "Dry Gas -
lnternal Corrosion Direct Assessment," PS-03-01-23O, "Direct Assessment Plan," and
PS-03-01-268, "lMP Quality Assurance", Appendix A require that the data elements
used for ICDA be gathered. This poor quality data could lead to the incorrect critical
angles being calculated and to ICDA regions being improperly determined.
9. S 192.927 (c) (see above)
(5) Other requirements. The IGDA plan must also include -
ii. provisions for applying more restrictive criteria when conducting
IGDA for the first time on a covered segment and that become less
stringent as the operator gains experience;
CE did not document where the more restrictive criteria were used in their ICDA plan, as
required by $192.927, and which are required when conducting ICDA for the first time on
a covered segment. These more restrictive criteria are for pre-assessment, indirect
inspection, direct examination, and post assessment steps of the ICDA process. CE
procedures PS-03-01-238, "Dry Gas - Internal Corrosion Direct Assessment," PS-03-01-
230, "Direct Assessment Plan," and PS-03-01-268, "lMP Quality Assurance", Appendix
A describe how ICDA assessments are to be conducted. the data to be collected and
what documentation needs to be retained. These plans and procedures reference the
ASME 831.8S for ICDA assessment requirements and 5192327. Although not
referenced, the draft NACE RP on Dry-Gas ICDA was also utilized. The CE procedures
do not document the more restrictive criteria as required in $192.927(b)(5)(iii) for each of
the four steps undertaken on an initial ICDA on a region or a segment. The rule is clear
that these criteria must be documented. CE also did not document how the more
restrictive criteria were applied in ICDAs for lines FT-1 1 and ADT-8.
10. S 192.929 What are the requirements for using Direct Assessment for Stress
Gorrosion Gracking (SCCDA)?
(b) General Requirements. An operator using direct assessment as an integrity
assessment method to address stress corrosion cracking in a covered pipeline
segment must have a plan that provides, at minimum, for -
(1) Data gathering and integration. An operator's plan must provide for a
systematic process to collect and evaluate data for all covered segments to
identify whether the conditions for SGC are present and to prioritize the covered



segments for assessment. This process must include gathering and evaluating
data related to SGC at all sites an operator excavates during the conduct of its
pipellne operations where the criteria in ASME/ANSI 831.8S, Appendix A3.3
indicate the potential for SCG. This data includes at minimum, the data specified
in ASME/ANSI 831.8S, Appendix A3.
CE's SCCDA plan does not require the gathering and evaluating of data related to SCC
at all sites it excavates during the conduct of its pipeline operations (not just covered
segments) where the criteria indicate the potential for SCC. CE procedures PS-03-01-
240, "Stress Corrosion Cracking Direct Assessment," PS-03-01-230, "Direct Assessment
Plan," and PS-03-01-268, "lMP Quality Assurance", Appendix A describe how SCCDA
assessments are to be conducted, the data to be collected and what documentation
needs to be retained. None of these procedures mandate that CE obtain data on non-
covered pipelines that may be susceptible to SCC as required in $'192.929,
Based on some of the data elements in CE's SCCDA program lhat were inspected, CE
did not review the data as required in their procedures. CE procedures PS-03-01-240,
"Stress Corrosion Cracking Direct Assessment," P5-03-01-230, "Direct Assessment
Plan," and PS-03-01-268, "lMP Quality Assurance", Appendix A require that the data
elements used for SCCDA be gathered. During the review of SCCDA pre-assessments,
data quality was determined to be poor or missing. 831.8S, Section A3.3 states, "Where
the operator is missing data, conseryative assumptions shall be used when performing
the risk analysis or alternatively the segment shall be prioritized higher."
CE's IMP does not provide for notification to PHMSA regarding its near-neutral SCC
plan. ASME 831.8S, Section A3.1 states, "Near-neutral type of SCC similar$ would
require an inspection and alternative mitigation plan." CE procedures PS-03-01-240,
"Stress Corrosion Cracking Direct Assessment," and PS-03-01-230, "Direct Assessment
Plan," require CE to notify PHMSA and/or local regulatory authorities if CE plans to use
"Other Technology" as defined in $192.921 (a)(4) (and follow the notification procedure
in $192.949). ASME 831.8S for SCCDA covers only high pH SCC and requires
operators to develop a plan for near neutral pH SCC, which CE has done by following
the procedure in NACE RP 0204 for near neutral SCC. This recommended practice is
not referenced in the rule and thus is considered an "Other Technology". As such, CE
must notify PHMSA and/or local regulatory authorities 180 days before proposing to use
the technology. CE has not yet used its near neutral pH SCCDA process nor has it
notified any regulatory authority.
CE's IMP does not specify the performance of a spike test, per ASME 831.8S, when it
has experienced an in-service leak or rupture attributable to SCC. ASME B31.8S,
Section A3.4 states, "lf the pipeline experiences an in-service leak or rupture, which is
attributed to SCC, the particular segment shall be subjected to a hydrostatic test (as
described below) within 12 months." CE procedures PS-03-01-240, "Stress Corrosion
Cracking Direct Assessment," and PS-03-01-230, "Direct Assessment Plan," state that
CE can use a pressure test to check for SCC. There is no procedure requirement to
perform a spike test following an in-service leak or rupture attributable to SCC. ASME
83'1.85 specifically mandates lhat operators use a spike hydrostatic pressure test
following an in-service leak or rupture attributable to SCC.



11. S 192.935 What additional preventive and mitigative measures must an operator
take?
(c) Automatic shut-off valves (ASV) or Remote control valves (RCV). lf an operator
determines, based on a risk analysis, that an ASV or RCV would be an efficient
means of adding protection to a high consequence area in the event of a gas
release, an operator must install the ASV or RGV. ln making that determination, an
operator must, at least, consider the following factors - swiftness of leak detection
and pipe shutdown capabilities, the type of gas being transported, operating
pressure, the rate of potential release, pipeline profile, the potential for ignition,
and location of nearest response personnel.
CE did not follow its procedure requiring that an analysis completed in conjunction with
the annual assessment inspection shall result in documentation of results from any
feasibility analysis of alternatives, including the installation of ACVs and RCVs. The
operator did not provide any documented technical justification either to install or not to
install ACVs or RCVs. CE's procedure PS-03-01-258, "Preventive and Mitigative
Measures," specifies that the operator shall document all actions considered and taken
to enhance public safety and/or environmental protection as identified from the risk
assessment and/or specific threat factors on each of the HCA pipeline segments. The
flow charts provided to the inspection team for preventive and mitigative evaluations did
not take into consideration segment specific risk data when determining measures to
implement. CE confirmed in discussions that rather than reviewing each segment
individually for preventive and mitigative measures that they applied more "global"
preventive and mitigative decisions across their system.
Proposed Civil Penaltv
Under 49 United States Code, $ 60122, you are subject to a civil penalty not to exceed
$100,000 for each violation for each day the violation persists up to a maximum of $1 ,000,000
for any related series of violations. The Compliance Officer has reviewed the circumstances
and supporting documentation involved in the above probable violations and has recommended
that you be preliminarily assessed a civil penalty of $95,000 as follows:
Item number
PENALTY
1.
$17,000
2.
$17,000
4.
$22,000
$17,000
7.
$22,000
Proposed Compliance Order
With respect to items 1 through 11 pursuant to 49 United States Code S 60118, the Pipeline and
Hazardous Materials Safety Administration proposes to issue a Compliance Order to
CenterPoint Energy Gas Transmission. Please refer to the Proposed Compliance Order, which
is enclosed and made a part of this Notice.
Response to this Notice
Enclosed as part of this Notice is a document entitled Response Options for Pipeline
Operators in Compliance Proceedings. Please refer to this document and note the



response options. Be advised that all material you submit in response to this
enforcement action is subject to being made publicly available. lf you believe that any
portion of your responsive material qualifies for confidential treatment under 5 U.S.C.
552(b), along with the complete original document you must provide a second copy of
the document with the portions you believe qualify for confidential treatment redacted
and an explanation of why you believe the redacted information qualifies for confidential
treatment under 5 U.S.C. 552(b). lf you do not respond within 30 days of receipt of this
Notice, this constitutes a waiver of your right to contest the allegations in this Notice and
authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in this
Notice without further notice to you and to issue a Final Order.
ln your correspondence on this matter, please refer to CPF 4-2007-1004 and for each document
you submit, please provide a copy in electronic format whenever possible.
Sincerely,
4wrM.$
R. M. Seeley Lt
Director, Southwest Region
Pioeline and Hazardous
Materials Safety Administration
Enclosures: Proposed Compliance Order
Response Options for Pipeline Operators in Compliance Proceedings
10



PROPOSED COMPLIANGE ORDER
Pursuant to 49 United States Code S 601 18, the Pipeline and Hazardous Materials Safety
Administration (PHMSA) proposes to issue to CenterPoint Energy Gas Transmission a
Compliance Order incorporating the following remedial requifements to ensure the compliance
of CenterPoint Energy Gas Transmission with the pipeline safety regulations:
1. In regard to ltem Number 1 of the Notice pertaining to potential threats to pipeline
integrity and specifically interactive threats, CE must implement their procedure PS-03-
01-216 and develop and implement a process to ensure that the evaluation of interactive
threats is addressed. CE must orovide an evaluation of the threat of interactive threats
for all covered segments.
2.
In regard to ltem Number 2 of the Notice pertaining to ASME 831.8S, Section 5 and the
requirement to develop minimum data requirements, CE must implement their procedure
PS-03-01-216 for all of the described threats and develop and implement a procedure
that also addresses Cyclic Fatigue. CE must develop specific documentation
requirements and provide documentation to support conclusions to eliminate threats
from HCAs in accordance with the minimum requirements specified by each of the
relevant ASME 831.8S section.
In regard to ltem Number 3 and 4 of the Notice pertaining to third party damage and
requirements of ASME 831.85, CE must develop the appropriate procedure(s) to
integrate inspection tools or external corrosion direct assessment data with data related
to encroachments or foreign line crossings to define potential indications of third party
damage in covered sections. CE must integrate ECDA data and lLl data with data
related to encroachment and foreign line crossing to evaluate the covered segment for
the threat of third party damage and provide documentation that those procedures have
been implemented related to each of the covered segments.
4.
In regard to ltem Number 5 of the Notice pertaining to ERW pipe and requirements of
ASME 831.8S, CE must revise its procedures to address the manufacturing threat by
specifying an assessment method(s) for each covered segment that is best suited for
identifying anomalies associated with specific threats for the segment. CE must identify
those locations where it may have used TFI technology for the identification of the
manufacturing threat; and where CE used TFI technology for the assessment of the
manufacturing threat, CE must reassess the segment using appropriate and approved
technologies.
6
In regard to ltem Number 6 of the Notice pertaining to ECDA general requirements, CE
must modify its procedures where appropriate; it must define and provide minimum data
requirements; it must document its conservative assumptions; it must document all
required feasibility assessments; and it must provide documentation for all indirect
inspection tools chosen relative to each of the HCAs in all covered sections.
6.
In regard to ltem Number 7 of the Notice pertaining to ECDA more restrictive criteria, CE
must document the requirement for more restrictive criteria required for pre-assessment,
indirect inspection, and direct examination when ECDA is applied for the first time. CE
must provide documentation for the application of more restrictive criteria on all locations
where ECDA was implemented.
11



7. In regard to ltem Number I of the Notice pertaining to the implementation of ICDA
procedures, CE must document the results of its feasibility analysis related to the ICDA
process and procedures, and CE must review the quality of pre-assessment data for all
completed lC direct assessments and develop quality controls for use of data in future
pre-assessments. CE must provide documentation of its feasibility analysis and it must
provide documentation to ensure that the application of the ICDA procedure to HCAs in
covered segments was adequate to ensure that the procedures were followed and that
the critical angles were properly calculated and evaluated.
a
In regard to ltem Number 9 of the Notice pertaining to more restrictive criteria required
for first time ICDA use, CE must provide documentation for the application of more
restrictive criteria required for pre-assessment, indirect inspection, direct examination,
and post assessment on all locations where ICDA was implemented. CE must
document for each specific assessment how the more restrictive criteria were applied.
o
In regard to ltem Number '10 of the Notice pertaining to using DA for Stress Corrosion
Cracking, CE's procedures must require the gathering and evaluating of data related to
SCC at all sites it excavates. CE must review the quality of pre-assessment data for all
completed SCC direct assessment and develop quality controls for the use of the data in
future pre-assessments. CE must provide for notification to PHMSA of its intent to use
its near-neutral SCC plan as a use of "Other Technology". CE must specify the
performance of a hydrostatic spike pressure test per ASME 83'l .8S for the event of an
in-service leak or rupture. CE must provide documentation to ensure that SCC is being
properly evaluated for all HCAs in covered segments.
10.
In regard to ltem Number 11 of the Notice pertaining to preventive and mitigative
measures, CE develop documentation associated with their technical justification either
to install or not to install ACVs or RCVs and provide the required documentation to
support its technical justifications with regard to ACVs or RCVs.
11.
CE must address the issues within this compliance order within 90 days after receipt of a
Final Order and submit to R. M. Seeley, Director, Southwest Region, Pipeline and
Hazardous Materials Safety Administration.
12.
CE shall maintain documentation of the safety improvement costs associated with
fulfilling this Compliance Order and submit the total to R. M. Seeley, Director, Southwest
Region, Pipeline and Hazardous Materials Safety Administration. Costs shall be
reported in two categories: 1) total cost associated with preparation/revision of plans,
procedures, studies and analyses, and 2) total cost associated with replacements,
additions and other changes to pipeline infrastructure.
t2

## Provenance

- Official: Yes
- Source: <https://primis.phmsa.dot.gov/enforcement-data/case/420071004>
- Source ID: `phmsa-enforcement`
- SHA-256: `88179d8fbeed9f8102bae0ad7bde43d260b460ef270b3c6ab74d5664eb6d78a5`
- Retrieved: 2026-08-20T04:44:44.458Z
- Exported: 2026-08-27T10:45:49.015Z
- Document slug: `phmsa-enforcement-420071004`

### Source metadata

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