# EL PASO NATURAL GAS CO — Notice of Probable Violation

**Citation:** CPF 420071007  
**Type / status:** enforcement / historical  
**Agency:** Pipeline and Hazardous Materials Safety Administration  
**Effective:** Not stated  
**Published:** 2007-07-24

CLOSED notice of probable violation citing 192.5(c), 192.907(a), 192.917(a), 192.933(a).

## Document text

Notice of Probable Violation involving EL PASO NATURAL GAS CO. PHMSA's enforcement data identifies the cited regulations as 192.5(c),  192.907(a),  192.917(a),  192.933(a). The case was opened on 2007-07-24 and is reported as closed as of 2012-05-29. Proposed civil penalty: $129,000. Assessed civil penalty: $129,000. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

420071007_Closure Letter_05292012.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071007/420071007_Closure%20Letter_05292012.pdf

420071007_Closure Letter_05292012_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071007/420071007_Closure%20Letter_05292012_text.pdf

420071007_Final Order_03102011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071007/420071007_Final%20Order_03102011.pdf

420071007_Final Order_03102011_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071007/420071007_Final%20Order_03102011_text.pdf

420071007_NOPV Post Hearing Response_06122008.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071007/420071007_NOPV%20Post%20Hearing%20Response_06122008.pdf

420071007_nopvpcppco_07242007_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071007/420071007_nopvpcppco_07242007_text.pdf

420071007_Closure Letter_05292012_text.pdf

CERTIFIED MAIL - RETURN RECEIPT REQUESTED
May 29, 2012
Mr. Daniel B. Martin
Senior Vice President, Pipeline Safety
El Paso Corporation
P.O. Box 2511
Houston, TX 77252-2511
Mr. Lee Hobbs
Senior Vice President and General Manager
US Pipelines
ANR Pipeline Corporation
TransCanada Corporation
P.O. Box 2446
Houston, TX 77252-2446
CPF 4-2007-1007
Dear Mr. Martin and Mr. Hobbs:
On March 10, 2011, the Pipeline and Hazardous Materials Safety Administration (PHMSA)
issued to El Paso Corporation and ANR Pipeline Company a Final Order in the above-referenced
case. This Order included a Compliance Order and Civil Penalty assessment. Payment of the
civil penalty was received on April 4, 2011. Based on our review of the documentation you
provided, it has been determined that you have complied with the terms of this Order.
Accordingly, this case is now closed and no further action is contemplated with respect to the
matters involved in this case. Thank you for your cooperation in this matter.
Sincerely,
R. M. Seeley
Director, Southwest region
Pipeline and Hazardous
Materials Safety Administration

420071007_Final Order_03102011_text.pdf

MAR 10 2011
Mr. Daniel B. Martin
Senior Vice President, Pipeline Safety
El Paso Corporation
P.O. Box 2511
Houston, TX 77252-2511
Mr. Lee Hobbs
Senior Vice President and General Manager
US Pipelines
ANR Pipeline Corporation
Trans Canada Corporation
P. O. Box 2446
Houston, TX 77252-2446
Re: CPF No. 4-2007-1007
Gentlemen:
Enclosed please find the Final Order issued in the above-referenced case. It makes findings of
violation, assesses a civil penalty of $129,000 against El Paso Corporation, and specifies
actions that need to be taken by both El Paso Corporation and ANR Pipeline Company to
comply with the pipeline safety regulations. The penalty payment terms are set forth in the
Final Order. When the civil penalty has been paid and the terms of the compliance order
completed, as determined by the Director, Southwest Region, this enforcement action will be
closed. Service of the Final Order by certified mail is deemed effective upon the date of
mailing, or as otherwise provided under 49 C.F.R. § 190.5.
Thank you for your cooperation in this matter.
Sincerely,
Jeffrey D. Wiese
Associate Administrator
for Pipeline Safety
Enclosure
cc: Mr. Rod Seeley
Director, Southwest Region, PHMSA
CERTIFIED MAIL – RETURN RECEIPT REQUESTED [7005 1160 0001 0040 0153]



U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, D.C. 20590
____________________________________
In the Matter of )
El Paso Pipeline Corporation, ) CPF No. 4-2007-1007
and )
ANR Pipeline Company, )
)
)
)
)
)
Respondents. )
____________________________________)
FINAL ORDER
During the weeks of April 17-21, May 1-5, and May 22-26, 2006, pursuant to 49 U.S.C.
§ 60117, representatives of the Pipeline and Hazardous Materials Safety Administration
(PHMSA), Office of Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of
the facilities and records of El Paso Pipeline Group, a division of El Paso Corporation (El
Paso) in Houston, Texas. The following pipeline systems were covered in the inspection:
Southern Natural Gas Co., Colorado Interstate Gas Co., El Paso Natural Gas Co., Tennessee
Gas Pipeline Co. (El Paso), ANR Pipeline Co., Mojave Pipeline Operating Co., and Bear
Creek Storage Co. Collectively, these systems include over 47,000 miles of natural gas
transmission pipelines.
As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to El
Paso, by letter dated July 24, 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 El Paso had committed various violations of 49 C.F.R. Part 192
and proposed assessing a civil penalty of $129,000 for two of the alleged violations. The
Notice also proposed ordering El Paso to take certain measures to correct the alleged
violations.
On February 22, 2007, one of El Paso’s subsidiaries, ANR Pipeline Company (ANR), was
acquired by a subsidiary of TransCanada Corporation.1
Both El Paso and ANR (collectively,
Respondents) responded to the Notice by letter dated August 23, 2007 (Response), contested
the allegations, and requested a hearing. An informal hearing was subsequently held on
April 30, 2008, in Houston, Texas, with an attorney from the Office of Chief Counsel,
PHMSA, presiding. At the hearing, Respondents were represented by counsel and submitted a
binder of documents and slides. After the hearing, the companies provided additional material
for the record by letter dated June 12, 2008 (Closing).
1 Response, at 1.



2
FINDINGS OF VIOLATION
The Notice alleged that Respondents violated 49 C.F.R. Part 192, as follows:
Item 1: The Notice alleged that Respondents violated 49 C.F.R. § 192.5(c), which states, in
relevant part:
§ 192.5 Class locations.
(a) . . .
(c) The length of Class locations 2, 3, and 4 may be adjusted as follows:
(1) . . .
(2) When a cluster of buildings intended for human occupancy requires a
Class 2 or 3 location, the class location ends 220 yards (200 meters) from the
nearest building in the cluster.
§ 192.903 What definitions apply to this subpart?
The following definitions apply to this subpart: . . .
High consequence area means an area established by one of the methods
described in paragraphs (1) or (2) as follows:
(1) An area defined as—
(i) A Class 3 location under §192.5; or . . . .
The Notice alleged that Respondents violated 49 C.F.R. § 192.5 by failing to properly delineate a
Class 3 location for High Consequence Area (HCA) 2718 on Line 1204, in a manner that
captured all buildings intended for human occupancy in the class location unit. Specifically, the
Notice alleged that the boundaries established under Respondents’ approach for delineating
Class 3 locations did not include approximately eight structures to the west of HCA 2718 on its
HCA map, as required by § 192.5. In their Response and at the hearing, the companies
contended that they interpreted the regulations on “clustering” to allow them to exclude these
eight buildings from the Class 3 area.
Under 49 C.F.R. Part 192, natural gas pipelines are categorized into different class locations.
The purpose of designating class locations is to apply higher safety standards to pipelines located
near densely populated areas and to protect people working and living in those areas. External
stresses on pipelines, the potential for damage from third parties, and other factors which
contribute to accidents all tend to increase with higher population densities in the vicinity of
pipelines, as do the consequences of accidents. Under the regulations, class locations are used as
a means of determining the frequency of monitoring pipelines and patrolling rights-of-way, for
conducting leakage surveys, and for determining the maximum allowable operating pressure
(MAOP) of gas pipelines.



3
A “class location unit” is defined under the regulations as an “area that extends 220 yards (200
meters) on either side of the centerline of any continuous 1-mile (1.6 kilometer) length of
pipeline.
”2 The class location is determined by the number and type of buildings in a given
lowest density and Class 4 being the highest. A group of buildings within the class location unit
is sometimes referred to as a “cluster” of buildings.
continuous one-mile length of pipeline known as the "sliding mile,”3 with Class 1 being the
Class 3 areas are defined in the pipeline safety regulations as “any class location unit that has 46
or more buildings intended for human occupancy.”4 Each separate dwelling unit in a multiple
dwelling unit building is counted as a separate building intended for human occupancy.5 Class 3
areas also include those where the pipeline lies within 100 yards of either a building or a small,
well-defined outside area, such as a playground, recreation area, outdoor theater, or other place
of public assembly, that is occupied by 20 or more persons on at least 5 days a week for 10
weeks in any 12-month period.6
The length of a Class 3 location unit, however, can be adjusted under certain circumstances.
Under § 192.5(c)(2), “[w]hen a cluster of buildings intended for human occupancy requires a
Class 2 or 3 location, the class location ends 220 yards (200 meters) from the nearest building in
the cluster,” rather than at the end of the one-mile class location unit that would otherwise
determine the end point of the unit. Clustering is therefore a means of reducing the length of a
Class 2 or 3 area in a sliding mile unit that requires a Class 2 or 3 location.7
In this case, however, Respondents argue that clustering should also serve as a means of
excluding buildings in the sliding mile from being part of the Class 3 area at all. They argue that
the group of eight buildings to the west of HCA 2718 on their HCA map should be excluded
from the Class 3 area, despite being located within the Class 3 sliding mile containing the other
buildings in the HCA.
2 49 C.F.R. § 192.5(a)(1).
3 For example, a pipeline can be divided into 1/8 mile segments and the number of buildings tallied for each
segment. The “sliding mile” would be calculated by summing eight consecutive 1/8 mile segment tallies, and
assigning the Class accordingly. Then the sliding mile is moved down by one segment and the process is repeated,
until the entire line has been evaluated and Classes assigned. Modern software programs typically calculate the
sliding mile foot by foot.
4 49 C.F.R. § 192.5(b)(3)(i).
5 49 C.F.R. § 192.5(a)(2).
6 49 C.F.R. § 192.5(b)(3)(ii).
7 For example, if all buildings in a sliding mile containing enough buildings to require a Class 3 location were
clustered in the middle of that sliding mile, the Class 3 area would end 220 yards from the nearest building (on
either side of the cluster through which the pipeline passes) rather than at the end of the one-mile class location unit
that would otherwise be the basis for classification. Thus, if the cluster itself were 200 yards in length, the total
length of the Class 3 area would be 640 yards.



4
They contend that a June 1996 rule amendment, which was reversed one month later, provides
preamble of the 1996 correction:
support for their position.8 In particular, Respondents cite the following discussion in the
“Since the revision was published, [the Research & Special Programs
Administration (RSPA)] has learned that many operators customarily apply
the cluster adjustment irrespective of buildings outside the cluster. We also
learned that this practice was tacitly accepted by RSPA enforcement
personnel and may be consistent with instruction at RSPA’s Transportation
Safety Institute.”9
Based upon this language, Respondents now contend that the NOPV issued in this proceeding
reflects a “new” requirement being imposed by PHMSA in the absence of notice and comment
rulemaking and that such new requirement is inconsistent with earlier actions by the agency.10
I reject Respondents’ argument for several reasons. First, § 192.5(c)(2) states that “[w]hen a
cluster of buildings intended for human occupancy requires a Class 2 or 3 location, the class
location ends 220 yards (200 meters) from the nearest building in the cluster.” Thus, as noted
above, the length of a Class 2 or 3 location can be reduced by clustering. The ability to conduct
a cluster adjustment, however, is explicitly premised on a given sliding mile unit and the
buildings therein requiring a Class 2 or 3 location to begin with. Moreover, § 192.5(c)(2) must
be read in conjunction with § 192.5(a)(1), which defines the term “class location unit,
” and
subsection (b)(3), which defines the term “Class 3 location.
” When all three subsections are read
together, Respondents’ interpretation of clustering contradicts the plain language and purpose of
the regulations. If an operator could use clustering to exclude groups of buildings in the sliding
mile unit from the unit’s Class 3 classification altogether, it would undermine the regulatory
requirement to use a continuous one-mile distance as the class location unit and, under some
circumstances, would circumvent the regulatory definition of a Class 3 location.
Second, it should be noted that the class location regulations for gas pipelines have been in place
for decades and the regulatory requirements reflected in the NOPV are not new. While
Respondents are correct that the amendment was reversed by the correction and the previous
language on cluster adjustment restored, it is important to note that the amendment being
reversed was itself only a narrow limitation stating that a cluster adjustment could only be used
for class location units where all buildings in the one-mile unit were in a single cluster.
11
The
amended rule did not allow buildings within the sliding mile to be excluded from the class
location even before the amendment was reversed. Restoring the status quo—that the cluster
8 See Final Rule, Regulatory Review; Gas Pipeline Safety Standards, 61 FR 28770 (June 6, 1996). See also
Correction of Final Regulation, Regulatory Review; Gas Pipeline Safety Standards; Correction, 61 FR 35139 (July
5, 1996).
9 61 FR 35139.
10 Respondents also argue that PHMSA had the opportunity to review its class location procedures during previous
El Paso inspections and did not issue any citations for non-compliance. The absence of citations for non-compliance
during one inspection visit, however, does not preclude PHMSA from citing the operator as the result of a
subsequent inspection.
11 61 FR 28772.



5
adjustment could potentially be used even when there was more than one Class 3 cluster in a
given one-mile Class 3 class location unit—in no way permits clustering to be used as a
mechanism to exclude individual or smaller groups of buildings from being part of a particular
Class 3 unit. Under the regulations in place both prior to the amendment and after the correction,
if individual or smaller groups of buildings are within a Class 3 class location unit, any cluster
adjustment must be conducted in a manner that includes them as part of a Class 3 cluster and the
Class 3 area endpoint of that cluster would be 220 yards from the outermost building.12
I find that the regulations do not permit the use of clustering as a mechanism to exclude
buildings within a Class 3 sliding mile from being part of a Class 3 area and therefore part of the
HCA. Respondents were unable to demonstrate that PHMSA published any guidance or other
material that would have justified reliance on the approach to clustering now advocated by
Respondents. Their approach is inconsistent with the plain language of the regulations and
would frustrate the purpose of the class location regulations, which is to ensure that higher safety
standards apply in more highly populated areas and thus provide greater protection for human
occupants in those areas.
Accordingly, after considering all of the evidence and the legal issues presented, I find that
Respondents violated 49 C.F.R. § 192.5(c) by failing to define a Class 3 location for HCA 2718
on Line 1204 in a manner that captured all buildings intended for human occupancy in that class
location unit.
Item 2: The Notice alleged that Respondents violated 49 C.F.R. § 192.907(a), which states:
§ 192.907 What must an operator do to implement this subpart?
(a) General. No later than December 17, 2004, an operator of a covered
pipeline segment must develop and follow a written integrity management
program that contains all the elements described in § 192.911 and that
addresses the risks on each covered transmission pipeline segment. The initial
integrity management program must consist, at a minimum, of a framework
that describes the process for implementing each program element, how
relevant decisions will be made and by whom, a time line for completing the
work to implement the program element, and how information gained from
experience will be continuously incorporated into the program. The
framework will evolve into a more detailed and comprehensive program. An
operator must make continual improvements to the program.
The Notice alleged that Respondents violated 49 C.F.R. § 192.907(a), by failing to develop and
follow, by December 17, 2004, an integrity management program that contained all the elements
described in § 192.911. That section states:
12 Nothing in this Final Order is intended to prevent an operator from making proper use of clustering to reduce the
length of a Class 2 or 3 area. For example, if a given sliding mile had a group of 47 buildings situated in the first
200 yards at one end of the sliding mile and a second group of 47 buildings situated in the last 200 yards at the other
end of the sliding mile and no buildings in between, the 420 yard lengths at either end would be Class 3 areas and
the 920 yards in the middle of the mile would not. However, if one or more buildings were later constructed in
between, the outermost building would become the last building in each of the two Class 3 clusters and that enlarged
cluster’s Class 3 area would have to be expanded to encompass that building plus 220 yards.



6
§ 192.911 What are the elements of an integrity management
program?
An operator's initial integrity management program begins with a
framework (see §192.907) and evolves into a more detailed and
comprehensive integrity management program, as information is gained and
incorporated into the program. An operator must make continual
improvements to its program. The initial program framework and subsequent
program must, at minimum, contain the following elements. (When indicated,
refer to ASME/ANSI B31.8S (incorporated by reference, see § 192.7) for
more detailed information on the listed element.)
(a) An identification of all high consequence areas, in accordance with
§ 192.905.
Specifically, the Notice alleged that Respondents failed to identify all HCA areas known as
“identified sites” and certain other areas meeting the HCA definition on the basis of having 20 or
more structures or certain class location changes.13
In their Response and at the hearing, El Paso and ANR acknowledged that several of their HCAs
were “misclassified” in 2004 and stated that they took action in 2005 to “re-classify those areas
which had earlier been misclassified as non-HCAs.
”14 Respondents, however, stated that they
believed they were in compliance with the regulations because they had developed a detailed and
comprehensive HCA identification process and had made ongoing improvements to this process.
The companies further argued that they should not be penalized for “the human errors involved
in the initial implementation.
”15
The relevant regulations required pipeline operators to identify all HCAs by December 17, 2004
(December 2004 Deadline). Based on the information in the record, 85 HCAs, totaling
approximately 32 miles in length, were not properly designated as HCAs by the December 2004
manner in which the process was implemented resulted in the failure to identify the 32 miles as
however, did not refute the allegation that they failed to identify these 85 areas as HCAs.
Deadline.16 sufficient to constitute compliance with this requirement. The companies acknowledged that the
HCA mileage. At the hearing, Respondents expressed the view that the missed areas were
statistically insignificant in light of the size of the companies’ overall systems. Respondents,
The fact that Respondents had an HCA identification process in place is not
Accordingly, after considering all of the evidence and the legal issues presented, I find that
Respondents violated 49 C.F.R. § 192.907(a) by failing to develop and follow an integrity
management program that included the identification of all HCAs on their pipeline routes by the
December 2004 Deadline. To the extent that the information and arguments offered by
Respondents are relevant to whether and at what level a civil penalty should be assessed, these
are discussed in the Assessment of Penalty section below.
13 49 C.F.R. § 192.903.
14 Closing, at 5.
15 Id., at 6.
16 Respondents’ PowerPoint Presentation dated April 30, 2008, slide 34.



7
Item 3: The Notice alleged that Respondents violated 49 C.F.R. § 192.917(a) which states:
§ 192.917 How does an operator identify potential threats to pipeline
integrity and use the threat identification in its integrity
program?
(a) Threat identification. An operator must identify and evaluate all
potential threats to each covered pipeline segment. Potential threats that
an operator must consider include, but are not limited to, the threats
listed in ASME/ANSI B31.8S (incorporated by reference, see §192.7),
section 2, which are grouped under the following four categories:
(1) Time dependent threats such as internal corrosion, external
corrosion, and stress corrosion cracking;
(2) Static or resident threats, such as fabrication or construction
defects;
(3) Time independent threats such as third party damage and outside
force damage; and
(4) Human error.
The Notice alleged that Respondents violated 49 C.F.R. § 192.917(a) by failing to identify and
evaluate all potential threats to each covered pipeline segment in their systems. Specifically, it
alleged that Respondents failed to consider the threats listed in ASME/ANSI B31.8S, section 2,
and to have a threat evaluation process that comprehensively integrated available data to enable
full consideration of interacting threat conditions on pipeline integrity.
17
In their Response and at the hearing, El Paso and ANR contended that their threat evaluation and
risk-ranking process did indeed account for combinations of threats. The companies indicated
that they had considered interactive threats in the risk-ranking process, in accordance with
Section 2.2 of ASME B31.8S, and provided several examples, including: (1) the interaction of
pre-1970 electric-resistance welded (ERW) pipe with land movement and frost heave conditions;
(2) the interaction of couplings, welds, bell and spigot pipe, wrinkle bends with frost heave or
backfill removal; and (3) the interaction of coating type and corrosion history. At the hearing,
OPS responded by pointing out that while Respondents did consider multiple threats, they did so
in an additive, as opposed to a multiplicative, manner.
Respondents’ method of considering multiple threats was to assign a numerical value to each of
the different threats and then to add those values together for purposes of ranking the overall
rather than to add them. They argued that the agency’s position constituted an “unwritten
threat level.18 Respondents argued that OPS’ allegation of violation was based upon the
agency’s position that the proper method of ranking risk was to multiply the various risk values
interpretation” having no factual predicate or scientific basis and that OPS was unable to derive
an appropriate multiplier for these interactive threats.
17 ASME B31.8S, Section 2.2, Integrity Threat Classification, states: “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.”
18 Closing, at 6.



8
A determination of whether Respondents complied with their obligations under the regulation
turns on whether the additive approach they took was sufficient to achieve the purpose of the
requirement. As commonly used, the term “interactive” means that the threats are influencing or
having an effect on each other. There is no question that multiple pipeline threats influence or
have effects on each other. In the context of analyzing interactive threats for purposes of
identifying and mitigating safety risks, the real question is how are the threats interacting? Two
or more threats acting on the same pipe location may raise the threat beyond what either threat
would do independently or if simply added together. For example, does the risk associated with
pre-1970 ERW pipe double with the risk of frost heave or does the potential for frost heave
increase the ERW pipe risk twenty times? Fully considering threats and performing effective
risk ranking requires at least some degree of technical analysis of how the threats interact.
The integrity management regulations are designed to be flexible and to allow operators to
develop their own processes for threat evaluation that are best suited to their particular pipeline
systems and operations. However, such flexibility does not mean that Respondents 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. In this case, Respondents need not use any
specific “plus” factor or any other particular logarithm or process. Rather, the regulations give
Respondents the flexibility to develop a procedure that realistically assesses the interactive
nature of threats. Only through such a realistic assessment, however, will Respondents have an
accurate indication of the potential threats to the integrity of their system.
Accordingly, after considering all of the evidence and the legal issues presented, I find that
Respondents violated 49 C.F.R. § 192.917(a) by failing to have a threat evaluation process that
comprehensively integrated available data to enable full consideration of interacting threat
conditions on pipeline integrity.
Item 4: The Notice alleged that Respondents violated 49 C.F.R. § 192.933(a), which states:
§ 192.933 What actions must be taken to address integrity issues?
(a) General requirements. An operator must take prompt action to
address all anomalous conditions that the operator discovers through the
integrity assessment. In addressing all conditions, an operator must evaluate
all anomalous conditions and remediate those that could reduce a pipeline's
integrity. An operator must be able to demonstrate that the remediation of
the condition will ensure that the condition is unlikely to pose a threat to the
integrity of the pipeline until the next reassessment of the covered segment.
If an operator is unable to respond within the time limits for certain
conditions specified in this section, the operator must temporarily reduce the
operating pressure of the pipeline or take other action that ensures the safety
of the covered segment. If pressure is reduced, an operator must determine
the temporary reduction in operating pressure using ASME/ANSI B31G
(incorporated by reference, see Sec. 192.7) or AGA Pipeline Research
Committee Project PR-3-805 (``RSTRENG''; incorporated by reference, see
Sec. 192.7) or reduce the operating pressure to a level not exceeding 80% of
the level at the time the condition was discovered. (See appendix A to this



9
part 192 for information on availability of incorporation by reference
information). A reduction in operating pressure cannot exceed 365 days
without an operator providing a technical justification that the continued
pressure restriction will not jeopardize the integrity of the pipeline.19
The Notice alleged that Respondents violated 49 C.F.R. § 192.933(a) by failing to take prompt
action to address two anomalous conditions on the 2nd North Main of the Southern Natural Gas
pipeline system that were discovered through the integrity assessment process. Specifically, the
Notice alleged that an anomalous condition (74% wall loss) at Mile Post (MP) 188-45+00 and an
anomalous condition at MP 190-49+31 (70% wall loss) were recoated and backfilled, whereas
the applicable requirements dictated pipe replacement, repair sleeves, or a reduction in MAOP.
In their Response and at the hearing, El Paso and ANR argued that they were not required to
perform repairs or implement a pressure reduction to address the two anomalies. They
contended that the class area involved in both locations had increased from Class 2 to Class 3.
They argued that the NOPV allegation was based on OPS using the Class 3 design factor and the
RSTRENG method to conclude that a pressure reduction was required in the absence of repairs,
whereas the companies elected to use the ASME B31G method, as permitted by the regulations,
and that the latter method allowed the use of the original (Class 2) design factor. Respondents
stated that they believed many other pipeline operators took the same approach. At the hearing,
OPS maintained that operators were required to make repairs consistent with the current class
location.
Class location requirements are central to determining the appropriate MAOP on gas pipelines.
The integrity management regulations were established for the purpose of increasing the level of
safety in HCAs and populated areas. Respondents’ argument that anomaly remediation
requirements should be based on the original design factor, rather than the current class location,
has the unfortunate consequence that older pipelines would continue to be operated with safety
margins below what would be permitted if a new pipeline were to be constructed in the same
area. Respondents are correct, however, that the ASME B31G method is a permissible method
for determining the appropriate pressure reduction under circumstances where an operator elects
not to perform a repair.
At the same time, pipeline operators have a general duty to “evaluate all anomalous conditions
this case, 74% and 70% of wall thickness respectively, are of sufficient magnitude that they
could reduce the pipeline’s integrity, particularly given potential interaction with other threats.
and remediate those that “could reduce” a pipeline’s integrity.”20 The depth of the anomalies in
Moreover, Respondents did not provide any information concerning the tolerances of the tool
that measured these anomalies; therefore, it is possible that the anomalies may even be 2-3%
deeper than reported. Respondents also did not provide any information concerning the growth
rates of these anomalies.
19 This regulation has since been amended (72 FR 39016; July 17, 2007).
20 49 C.F.R. § 192.933(a).



10
If Respondents were allowed to simply recoat and backfill these locations without remediating
them, the anomalies could potentially grow to a magnitude exceeding 80% of wall thickness
before the next reassessment were conducted. This could potentially be as long as five years.
In addition, these anomalies were located in a HCA and therefore posed a heightened threat to
public safety. Under the circumstances, a prudent pipeline operator should have either: (1)
concluded that these two anomalous conditions could reduce the pipeline’s integrity and
performed repairs or implemented a pressure reduction to ensure safe operation; or (2) performed
further technical study of the nature of the anomalies and their growth rates to justify a
determination that the anomalies could not reduce the pipeline’s integrity. I am not persuaded
that the generic approach taken by Respondents, of simply applying ASME B31G, met their
obligation to evaluate all anomalous conditions and remediate those that could reduce the
pipeline’s integrity.
Accordingly, after considering all of the evidence and the legal issues presented, I find that
Respondents violated 49 C.F.R. § 192.933(a) by failing to take prompt action to address two
anomalous conditions on the 2nd North Main of the Southern Natural Gas pipeline system.
These findings of violation will be considered prior offenses in any subsequent enforcement
action taken against Respondents.
ASSESSMENT OF PENALTY
Under 49 U.S.C. § 60122, Respondents are subject to an administrative civil penalty not to
exceed $100,000 per violation for each day of the violation, up to a maximum of $1,000,000 for
any related series of violations. In determining the amount of a civil penalty under 49 U.S.C.
§ 60122 and 49 C.F.R. § 190.225, I must consider the following criteria: the nature,
circumstances, and gravity of the violation, including adverse impact on the environment; the
degree of Respondents’ culpability; their history of prior offenses; their 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 Respondents 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 $129,000 for the violations cited above.
In the instant case, El Paso was the parent company of ANR at the time of the violations.
Therefore, it is the sole “person” financially liable for penalties assessed pursuant to 49 C.F.R.
§ 190.223 in this proceeding.
As a general matter, El Paso also argues that § 60109(c)(9)(A)(iii) only permits PHMSA to act
under § 60109(a)(2) to order an operator to revise its integrity management program with a
Notice of Amendment type of enforcement action (i.e., to require Respondents to amend their
plans and procedures). The company further argues that this statute precludes or does not give
PHMSA the authority to act under any other section of Chapter 601 to enforce integrity
management program regulations by issuing compliance orders and civil penalties.



11
With the enactment of the Pipeline Safety Improvement Act of 2002 (PSIA), the U.S. Congress
directed the Department of Transportation, PHMSA, to establish and issue regulations detailing
standards for the implementation of an integrity management program.
The authority set forth in §§ 60119 and 60122 to enforce pipeline safety standards, laws and
regulations through compliance orders and civil penalties has been codified since 1979 and
nothing in PSIA or the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006
(PIPES Act) affected this authority.
Any suggestion that, prior to the PIPES Act, section 60109(c)(9)(A)(iii) limited the agency’s
authority with respect to operator conduct and to only require an operator to amend an
inadequate or noncompliant integrity management program is therefore incorrect.
Considering the authority established in §§ 60118 and 60122; the legislative history of both
PSIA and the PIPES Act, including H.R. Rep. No. 109-717, Part 2, § 2(g), at 16 (Dec. 5, 2006);
and the legal issues presented, I find that PHMSA had the authority and did properly exercise the
full spectrum of enforcement tools upon a determination that a risk analysis or integrity
management program is inadequate or noncompliant.
Item 2: The Notice proposed a civil penalty of $49,000 for Respondents’ violation of
§ 192.907(a) for failing to have and follow an integrity management program that included the
identification of all HCAs on their pipeline routes by the December 2004 Deadline.
The identification of all HCAs is a key step in the integrity management process. Failure to
indentify all HCAs could hinder an operator’s integrity management program and adversely
impact safety. In their Response and at the hearing, the companies stated that the non-
compliance was the result of “human error.” Many violations of regulatory requirements,
however, are the result of human error. That does not negate the seriousness of the non-
compliance. Respondents also noted that only 32 miles of pipeline were affected. However, 32
miles of pipeline is significant, even on a system as large as Respondents’
. The companies have
presented no information or arguments that warrant a reduction in the civil penalty amount
proposed in the Notice. Accordingly, having reviewed the record and considered the assessment
criteria, I assess El Paso a civil penalty of $49,000 for violation of 49 C.F.R. § 192.907(a).
Item 4: The Notice proposed a civil penalty of $80,000 for Respondents’ violation of
§ 192.933(a), for failing to take required action to promptly address two anomalous conditions
on the 2nd North Main of the Southern Natural Gas pipeline system.
The failure to promptly remediate anomalous conditions of the magnitude involved in this case
can have direct safety impacts on the public. While Respondents raised legitimate questions
concerning whether the decision not to repair or remediate the two cited anomalies was allowed
by the code, having determined that a violation occurred, the gravity of the violation is
sufficiently serious to warrant the civil penalty amount proposed in the Notice.
Accordingly, having reviewed the record and considered the assessment criteria, I assess El Paso
a civil penalty of $80,000 for violation of 49 C.F.R. § 192.933(a).



12
In summary, having reviewed the record and considered the assessment criteria for each of the
Items cited above, I assess El Paso a total civil penalty of $129,000.
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’s telephone number is (405) 954-8893.
Failure to pay the $129,000 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
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 district
court of the United States.
COMPLIANCE ORDER
The Notice proposed a compliance order with respect to Items 1−4 in the Notice for violations of
49 C.F.R. §§ 192.5(c), 192.907(a), 192.917(a), and 192.933(a), respectively. 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,
Respondents are ordered to take the following actions to ensure compliance with the pipeline
safety regulations applicable to their operations:
1. With respect to the violation of § 192.5(c) (Item 1), El Paso must re-establish the
proper boundary for HCA 2718 in accordance with applicable requirements. Both El
Paso and ANR must verify all other HCA boundaries for accuracy and ensure any
areas initially excluded from their original HCA boundaries are in compliance with
the 49 C.F.R. Subpart O integrity management requirements.
2. With respect to the violation of § 192.907(a) (Item 2), Respondents must revise their
HCA identification processes as necessary to ensure the complete and accurate
identification of all HCAs and take steps to ensure that their personnel are trained to
fully utilize such processes.
3. With respect to the violation of § 192.917(a) (Item 3), Respondents must revise their
respective threat evaluation processes as necessary to include the use of
comprehensively integrated available data to enable full consideration of interacting
threat conditions on pipeline integrity.
4. With respect to the violation of § 192.933(a) (Item 4), Respondents must perform
corrosion repairs as necessary at the specified locations based on their current
classing.



13
5. Within 90 days following receipt of this Final Order, submit documentation
demonstrating completion of Items 1-4 above to the Director, Southwest Region,
PHMSA. Include documentation reporting the costs associated with fulfilling this
compliance order and submit the total to the Regional Director. Report costs 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.
The Regional Director may grant an extension of time to comply with any of the required items
upon a written request timely submitted by either Respondents and demonstrating good cause for
an extension.
Failure to comply with this Order may result in the 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, Respondents have a right to submit a petition for reconsideration of
this Final Order. Should either Respondent elect to do so, 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 Respondents, provided they contain a brief statement of the
issue(s) and meet all other requirements of 49 C.F.R. § 190.215. The filing of a petition
automatically stays the payment of any civil penalty assessed. Unless the Associate
Administrator, upon request, grants a stay, all other terms and conditions of this Final Order are
effective upon service in accordance with 49 C.F.R. § 190.5.
___________________________________ __________________________
Jeffrey D. Wiese Date Issued
Associate Administrator
for Pipeline Safety

## Provenance

- Official: Yes
- Source: <https://primis.phmsa.dot.gov/enforcement-data/case/420071007>
- Source ID: `phmsa-enforcement`
- SHA-256: `90bc1279cbaed17b69f1c140777f6d771368a53a92cef82ce4102d72b0db4f40`
- Retrieved: 2026-08-20T04:44:44.458Z
- Exported: 2026-08-22T19:46:59.783Z
- Document slug: `phmsa-enforcement-420071007`

### Source metadata

```json
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```