# SFPP, LP — Notice of Probable Violation

- **operation:** document
- **citation:** CPF 420065023
- **title:** SFPP, LP — Notice of Probable Violation
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2006-05-30
- **effective on:** Not available
- **summary:** CLOSED notice of probable violation citing 195.406(b), 195.410(a)(1), 195.420(c), 195.573(a)(1), 195.579(a).
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- **app url:** https://regulus.evalyn.ai/document/phmsa-enforcement-420065023
- **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/420065023
**body:**

Notice of Probable Violation involving SFPP, LP. PHMSA's enforcement data identifies the cited regulations as 195.406(b),  195.410(a)(1),  195.420(c),  195.573(a)(1),  195.579(a). The case was opened on 2006-05-30 and is reported as closed as of 2012-07-19. Proposed civil penalty: $35,000. Assessed civil penalty: $35,000. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

420065023_Closure_07192012.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420065023/420065023_Closure_07192012.pdf

420065023_Closure_07192012_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420065023/420065023_Closure_07192012_text.pdf

420065023_FinalOrder_08312010.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420065023/420065023_FinalOrder_08312010.pdf

420065023_FinalOrder_08312010_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420065023/420065023_FinalOrder_08312010_text.pdf

420065023_FinalOrder_08312010_text.pdf

AUG 31 10
Mr. Ronald G. McClain
Vice President, Operations and Engineering
Products Pipelines
Kinder Morgan Energy Partners, L.P.
500 Dallas Street, Suite 1000
Houston, TX 77002
Re: CPF No. 4-2006-5023
Dear Mr. McClain:
Enclosed please find the Final Order issued in the above-referenced case. It makes findings of
violation, assesses a civil penalty of $35,000, and specifies actions that need to be taken by
Kinder Morgan Energy Partners, L.P., 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. Paul Biancardi, Counsel for Kinder Morgan Energy Partners, L.P.
5818 Beaver Falls Drive
Kingwood, Texas 77345
Mr. R.M. Seeley, Director, Southwest Region, PHMSA
CERTIFIED MAIL – RETURN RECEIPT REQUESTED [7009 1410 0000 2472 2797]



U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, D.C. 20590
____________________________________
In the Matter of )
Kinder Morgan Energy Partners, L.P., ) CPF No. 4-2006-5023
)
)
)
Respondent. )
____________________________________)
FINAL ORDER
On December 13-17, 2004, and August 1-5, 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 facilities and
records of Kinder Morgan Energy Partners, L.P. (Respondent or KM), in New Mexico, Texas,
and Louisiana. In addition, from November 28 through December 16, 2005, pursuant to 49
U.S.C. § 60117, a representative of the Arizona Corporation Commission, as agent for OPS,
conducted an on-site pipeline safety inspection of Respondent’s facilities and records in Arizona.
The inspection covered facilities and records pertaining to a portion of Respondent’s Santa Fe
Pacific Pipeline (SFPP) and Cypress Pipeline (Cypress) systems.
liquid hydrocarbon products and consists of approximately 372 miles of pipeline in New Mexico
and Texas and 671 miles of pipeline in Arizona. Cypress transports Highly Volatile Liquids
(HVLs), including ethane and propane, and consists of approximately 104 miles of pipeline in
Texas and Louisiana.
1 SFPP transports various
As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to
Respondent, by letter dated May 30, 2006, a Notice of Probable Violation, Proposed Civil
Penalty, and Proposed Compliance Order (Notice). In accordance with 49 C.F.R.
§ 190.207, the Notice proposed finding that Respondent had violated 49 C.F.R. §§ 195.406(b),
195.410(a)(1), 195.573(a)(1), and 195.579(a), assessing a civil penalty of $35,000 for the alleged
violations, and ordering Respondent to take certain measures to correct the alleged violations.
The Notice also proposed finding that Respondent had committed certain probable violations of
49 C.F.R. 195.420(c) and warning Respondent to take appropriate corrective action to address
them or be subject to future enforcement action.
1 Both pipeline systems are owned by Kinder Morgan Energy Partners, L.P., and operated by its subsidiaries. The
subject portion of the SFPP pipeline system is operated by SFPP, L.P., and the Cypress Pipeline system is operated
by Kinder Morgan Operating, L.P.



2
KM responded to the Notice by letter dated June 30, 2006 (Response). The company contested
all the allegations and requested a hearing. At Respondent’s request, the materials in the OPS
case file, including the OPS Violation Report, were provided to Respondent on January 24, 2007.
A hearing was held on February 9, 2007, in Houston, Texas, with an attorney from the Office of
Chief Counsel, PHMSA, presiding. Respondent provided numerous documents at the hearing
(Hearing Exhibits), which have been incorporated into the record for this case. Respondent was
represented by counsel in this matter. Respondent arranged for an unofficial transcript of the
hearing and provided copies to PHMSA on March 26, 2007.2 After the hearing, KM provided
additional information on March 26, 2007 (Closing).
FINDINGS OF VIOLATION
The Notice alleged that Respondent violated 49 C.F.R. Part 195, as follows:
Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 195.406(b), which states:
§ 195.406 Maximum operating pressure.
(a) …
(b) No operator may permit the pressure in a pipeline during surges or
other variations from normal operations to exceed 110 percent of the
operating pressure limit established under paragraph (a) of this section.
Each operator must provide adequate controls and protective equipment to
control the pressure within this limit.
The Notice alleged that KM violated 49 C.F.R. § 195.406(b) by failing to provide adequate
controls and protective equipment to control the pressure on its SFPP and Cypress pipelines
within the limits established under § 195.406(a). Specifically, it alleged that neither system used
full-flow pressure relief valves and breakout tanks to relieve surges. At the hearing, OPS
presented evidence that its inspectors observed that KM’s pipelines did not have such pressure
control devices, which led them to seek other evidence to indicate whether the lines had adequate
controls and protective equipment. KM contested this allegation on both factual and legal
grounds.
First, KM characterized Item 1 as an alleged failure to provide documentation of compliance
with § 195.406(b).3
Respondent argued that § 195.406(b) contains no documentation
requirement and that therefore OPS’ allegation was based on a new interpretation of the
regulation, of which KM did not have fair notice. I reject KM’s characterization of the allegation
and its fair notice argument. During the inspection, OPS observed that Respondent’s systems did
not have full-flow pressure relief valves or breakout tanks. These devices are commonly used to
2 I consider the transcript to be unofficial. PHMSA noted that the transcript contains numerous errors and
misattributions, but because of the informal nature of this matter, errors were not corrected before the transcript was
finalized and made part of the record.
3 Response at 2.



3
relieve pressure on pipelines during surges or other types of overpressure situations. The
absence of these devices led OPS to question whether Respondent had the adequate controls and
protective equipment required by the regulation. The Notice simply noted that KM could not
produce any documentation that it had taken steps to protect its systems from overpressure or
that it had actually considered the need for surge prevention. Nothing in the record indicates that
OPS attempted to impose any sort of new documentation requirement or to cite KM for a failure
to maintain records under § 195.406(b).
Second, KM argued that OPS, at the hearing, appeared to base the allegation of violation on a
statutory provision found in 49 U.S.C. § 60117(b) of the Pipeline Safety Laws. KM argued that
no statutory violation could be found since none had been alleged in the Notice. Section
60117(b) requires pipeline owners or operators to “(1) maintain records, make reports, and
provide information the Secretary requires; and (2) make the records, reports, and information
available when the Secretary requests.
require pipeline owners or operators to provide documentation of compliance, OPS made clear in
the Notice and at the hearing that the basis of its allegation was KM’s failure to provide adequate
controls and protective equipment, as required by § 195.406(b).
”4 Although § 60117(b) gives PHMSA broad authority to
Third, Respondent provided several documents in support of the argument that it had considered
surge overpressure and had provided adequate controls and protective equipment on its
pipelines.5
Specifically, Respondent provided pump station discharge and emergency and abnormal
operation records. KM argued that these records supported its contention that pipeline pressures
had never exceeded the 110% Maximum Operating Pressure (MOP) limit set by the regulation
and that OPS had failed to show that the company had ever exceeded the 110% limit.
however, did not allege that Respondent had exceeded such MOP on the subject pipelines but,
rather, that KM had failed to provide adequate controls and protective equipment to prevent the
pressure from exceeding 110% of MOP. Furthermore, Respondent’s operating history does not
confirm the adequacy of controls and protective equipment, nor does it indicate that surge
overpressure had been adequately analyzed. A lack of historical overpressure events on these
systems may have been more a matter of luck than compliance with the regulation.
6 OPS,
KM also provided various MOP studies that had been conducted of the SFPP and Cypress
pipelines, but these too fail to establish that the company had provided adequate controls and
protective equipment to control pressure within the prescribed limits.
7
The SFPP studies only
4 49 U.S.C. § 60117(b). The authorities vested in the Secretary of Transportation by § 60117 have been delegated to
PHMSA by 49 C.F.R. § 1.53.
5 Response at 2.
6 Id.
7 Hearing Exhibit 1A, SPEC SERVICES, PRELIMINARY WESTERN PIPELINES MAXIMUM OPERATING PRESSURE STUDY,
L.S. 17-19/21/22 EL PASO– TUCSON (23 Dec. 2003); Hearing Exhibit 1B, SPEC SERVICES, PRELIMINARY WESTERN
PIPELINES MAXIMUM OPERATING PRESSURE STUDY, L.S. 4/5/6/86 EL PASO – TUCSON (23 Dec. 2003); Hearing



4
considered a narrow range of scenarios and did not account for others that could lead to
overpressure events. For example, the studies did not account for the possibility of a pressure
wave rebound off a suddenly closed valve after an abnormal station shut-down. Nor did the
studies consider the possibility of valve closures other than for station valves. The studies even
acknowledged the possibility that overpressure events could occur. Finally, KM made
significant modifications to the SFPP system after the completion of the studies in 2003. Such
modifications could have changed what overpressure equipment and controls were necessary to
protect SFPP, yet there is no evidence in the record that the effects of such modifications on the
risk of overpressure were ever considered. Without considering such modifications, Respondent
could not accurately determine whether its controls and protective equipment were adequate.
As for KM’s Cypress study, it was completed in 2007, long after the inspection had been
conducted and the Notice issued in this proceeding.
surge overpressure scenario involving the closure of a delivery valve. Other potential surge
overpressure scenarios were not considered at all. Therefore, I find that the 2007 study is not
probative of whether Respondent provided adequate controls and protective equipment on the
Cypress line as of the dates of the 2004-05 inspections.
8 In addition, the study evaluated a single
Finally, KM argued that an engineer for Enron, the previous operator of the Cypress Pipeline,
had informed Respondent that a surge study had been performed on that line prior to KM’s
acquisition. Respondent stated that this engineer had represented that “surge was not an issue for
In the absence of evidence beyond an undated, undocumented verbal statement, I cannot
this HVL pipeline.”9 KM provided no documentation of this study or basis for such a statement.
conclude that KM provided adequate controls and protective equipment on the Cypress Pipeline.
Inherent in the requirement that KM provide “adequate” controls and protective equipment is the
company’s obligation to use reasonable means to determine what is “adequate” for its own
pipeline systems and to document such a decision-making process. If Respondent has not
performed such an analysis, it might, for example, select undersized protective equipment or an
insufficient number of pressure control devices. Without such an analysis, neither Respondent
nor PHMSA can determine whether it has simply been a matter of luck that an overpressure
situation has not occurred.
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 195.406(b) by failing to provide adequate controls and protective equipment to control the
pressure on its SFPP and Cypress systems within the limits established according to
§ 195.406(a).
Exhibit 1C, ANALYSIS OF RECOMMENDATIONS, PRELIMINARY 2003 SURGE REPORTS FOR 8" AND 12" EI PASO TO
TUCSON PIPELINE.
8 Hearing Exhibit 1D, LINDEN PROFESSIONAL SERVICES, CYPRESS PIPELINE SYSTEM HYDRAULIC and SURGE ANALYSIS
(1 Feb. 2007).
9 Response at 2.



5
Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 195.410(a)(1), which states:
§ 195.410 Line markers.
(a) Except as provided in paragraph (b) of this section, each operator
shall place and maintain line markers over each buried pipeline in
accordance with the following:
(1) Markers must be located at each public road crossing, at each
railroad crossing, and in sufficient number along the remainder of each
buried line so that its location is accurately known.
The Notice alleged that KM violated 49 C.F.R. § 195.410(a)(1) by failing to place and maintain
line markers over its SFPP Pipeline in sufficient number so that the line’s location was
accurately known. Specifically, it alleged that when crossing cultivated agricultural fields, the
markers on the far side of the field often could not be seen. The Notice also alleged that the
location of the pipeline could not be discerned in some locations because of tall brush on the
right-of-way.
KM objected to the so-called “line-of-sight” test used by OPS to determine the adequacy of
Respondent’s pipeline marking in cultivated fields and argued that it did not have fair notice that
the regulation required such a test. PHMSA acknowledges that while many operators follow the
so-called “line-of-sight” test, as applied in the Notice in this case, many others do not.
Furthermore, the regulation does not expressly require “line-of-sight.” In an effort to arrive at
greater consensus on this and other line-marking issues, PHMSA convened a public workshop in
such circumstances, I find it appropriate to withdraw this portion of the allegation of violation.
Such withdrawal neither constitutes an interpretation of § 195.410(a)(1) nor prejudices future
potential enforcement action against Respondent or any other operator. Having withdrawn this
portion of the allegation, I do not reach Respondent’s fair notice argument on the “line-of-sight”
test.
2008 and is currently considering whether to issue a notice of proposed rulemaking.10 Under
KM did not contest the allegation that in some areas the location of the pipeline could not be
discerned because of tall brush in the right-of-way.11 KM indicated that it would “review the
[right-of-way] for tall brush impeding the view of the line markers and eliminate the same.”12
Accordingly, based on the foregoing, I find that Respondent violated 49 C.F.R. § 195.410(a) by
failing to maintain line markers over the SFPP pipeline so that its location was accurately known.
Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 195.573(a)(1), which states:
10 PHMSA held a public workshop on February 20-21, 2008, in Houston, Texas, to discuss, among other issues, the
placement of line markers. Pipeline Safety: Workshop on Public Awareness Programs for Pipeline Operators and
Location of Line Markers, 73 Fed. Reg. 223 (Jan. 2, 2008).
11 Response at 3.
12 Id.



6
§ 195.573 What must I do to monitor external corrosion control?
(a) Protected pipelines. You must do the following to determine
whether cathodic protection required by [Subpart H] complies with
§ 195.571:
(1) Conduct tests on the protected pipeline at least once each calendar
year, but with intervals not exceeding 15 months. However, if tests at
those intervals are impractical for separately protected short sections of
bare or ineffectively coated pipelines, testing may be done at least once
every 3 calendar years, but with intervals not to exceed 39 months.
The Notice alleged that KM violated 49 C.F.R. § 195.573(a) by failing to properly conduct tests
on its cathodically protected pipelines. Specifically, it alleged that KM failed to consider IR
drop13 during the Company’s annual corrosion surveys on the SFPP and Cypress pipeline
systems.
The primary purpose of the annual testing required by § 195.573(a)(1) is to provide an operator
with sufficient information about its cathodic protection system to determine whether it is
meeting the requirements of § 195.571. Such information allows an operator to take action to
remedy any inadequate cathodic protection and to comply with one or more of the applicable
criteria and other considerations contained in paragraphs 6.2 and 6.3 of NACE Standard
RP0169-2002 (NACE Standard).
14
Cathodic protection can limit external corrosion on buried pipelines through the application of
direct electric current to the metal of the pipeline. Protection is achieved when current flows to
the metal in an amount sufficient to prevent the loss of metal from the pipeline to the
surrounding environment. If insufficient current is provided, corrosion can result. The NACE
Standard provides reference criteria against which Respondent can measure the flow of electric
current to or from its pipelines (pipe-to-soil potential).
In order to obtain an accurate reading of pipe-to-soil potential, Respondent must consider IR
drop when it conducts annual tests of its cathodic protection system. If IR drop is not
considered, cathodic protection may appear to meet the criteria required by § 195.571, when, in
fact, it does not. Therefore, when IR drop is not considered, such surveys do not achieve their
intended purpose and therefore do not comply with § 195.573(a).
Paragraph 6.2 of the NACE Standard sets out four methods for considering IR drop (Methods),
and provides, in relevant part:
13 IR drop is an error in the pipe-to-soil voltage measurement caused by the electrical resistance of the soil in which
the pipeline is buried.
14 NACE INTERNATIONAL, NACE STANDARD RP0169-2002 CONTROL OF EXTERNAL CORROSION ON UNDERGROUND
OR SUBMERGED METALLIC PIPING SYSTEMS. This standard is incorporated by reference into the pipeline safety
regulations; see 49 C.F.R. § 195.3.



7
Note: Consideration is understood to mean the application of sound
engineering practice in determining the significance of [IR] drops by
methods such as:
6.2.2.1.1.1 Measuring or calculating the [IR] drop(s);
6.2.2.1.1.2 Reviewing the historical performance of the cathodic
protection system;
6.2.2.1.1.3 Evaluating the physical and electrical characteristics
of the pipe and its environment; and
6.2.2.1.1.4 Determining whether or not there is physical evidence
of corrosion.
SFPP System
Respondent uses an impressed current cathodic protection system on the SFPP system. During
the hearing, OPS argued that KM’s 2004 annual cathodic protection survey data revealed that the
company was not accounting for IR drop at the test locations where it used the 850 mV NACE
criteria. OPS contended that Respondent was taking IR drop readings from certain testing
locations and extrapolating the readings to other locations, rather than measuring the actual IR
drop at each one. According to OPS testimony, the IR drop could be different among various
test locations due to differences in soil and environmental conditions. OPS asserted that when
KM extrapolated IR drop to other testing locations, rather than considering the actual IR drop at
each one, it may not have had an accurate indication of IR drop.
Respondent acknowledged that it was extrapolating IR drop measurements when performing
cathodic protection testing, but argued that its historical experience from hundreds of test
locations with similar conditions was consistent with “sound engineering practices” and
therefore in compliance with the regulation. In support of its argument, Respondent cited a 1991
industry training guide on cathodic protection that stated: “Although it is beneficial to remove IR
drop from all potential readings, it is not necessary to measure IR drop at each location each time
a potential reading is made. IR drop measurements made at one location may be applied to other
not establish compliance with either the regulation or the NACE criteria incorporated therein.
similar locations.”15 The statements in the FERA Corporation’s training document, however, do
I find that Respondent’s practice of extrapolating IR drop measurements from certain test
locations to others is not consistent with the NACE Standard and therefore does not satisfy the
annual testing requirement set out in § 195.573. Respondent measured IR drop, a permissible
Method under the NACE Standard, but only at some locations. From location to location and
year to year, environmental and soil conditions can change, resulting in changed soil resistivity
and, consequently, different IR drops. Respondent’s practice of extrapolating IR drop data
across its system does not account for the potential for environmental and soil changes at each
15 Hearing Exhibit 4E, FERA CORPORATION, IR DROP, 4 (1991).



8
test location. This practice does not satisfy the NACE Standard because it could leave
Respondent with an inaccurate understanding of IR drop on its system.
Paragraph 6.3 of the NACE criteria specifically recognizes the potential for different soil and
environmental conditions at different locations when it provides that “once determined, the
voltage drop(s) may be used for correcting future measurements at the same location, providing
conditions such as pipe and cathodic protection system operating conditions, soil characteristics,
may, in certain circumstances, use the voltage drop at a particular location to analyze and
consider future readings at the same location, but not at others.
and external coating quality remain similar” (emphasis added).16 In other words, an operator
Finally, Respondent argued that the leak history of the SFPP system demonstrated the adequacy
of its cathodic protection system. I disagree. As noted above, an absence of leaks may simply
be a matter of luck rather than evidence of compliance with the regulation.
Cypress System
Respondent uses galvanic anode groundbeds to provide cathodic protection on the Cypress
system. Respondent’s galvanic anodes are connected directly to the pipeline. In this design, the
anodes corrode, or self-sacrifice, in order to protect the pipeline from corrosion. These
sacrificial anodes must be periodically replaced when they become corroded to the extent they no
longer provide protection. Unlike an impressed current system, no external power source is
used. While the Cypress system has a different design than the SFPP system, the cathodic
protection principles are generally the same.
The Notice alleged that Respondent did not account for IR drop in its annual cathodic protection
surveys of the Cypress system. In its Response, during the hearing, and in its Closing,
Respondent argued that it had considered IR drop on the Cypress system through “sound
engineering practice,” as permitted by NACE Standard paragraph 6.2.2.1.1.17 KM asserted that
although it did not measure or calculate IR drops on the Cypress pipeline directly, it employed a
combination of the three other Methods for “consideration” of IR drop,
18 as permitted by NACE
Standard paragraph 6.2.
19
First, Respondent argued that it used 2004 in-line inspection (ILI) data to show that there were
very few external corrosion anomalies on the Cypress Pipeline.20
Respondent also argued that
16 NACE STANDARD, 6.3.1.
17 Closing at 11.
18 Response at 5-6; Closing at 10-11.
19 Id. Respondent stated that OPS had a “grievance with RP 169 for permitting the use of ‘sound engineering
practices,’” and wished to “substitute its engineering judgment for that of the operator.” Closing at 11. On the
contrary, it appears that OPS did not have an issue with the use of sound engineering practices, but instead with how
Respondent demonstrates that its practices are sound.
20 Response at 5; Hearing Exhibit 4H.



9
the ILI data served as an evaluation of the physical condition of the pipe and revealed that the
cathodic protection system was performing well.
21 OPS countered, however, that ILI is just a
snapshot in time of the corrosion profile of the pipeline. OPS also pointed out that the NACE
Standard cautions operators that ILI may not detect certain kinds of corrosion.
Respondent may use ILI as part of a larger program for determining the adequacy of corrosion
control, ILI alone does not show that an operator is adequately considering IR drop.
22 While
Second, Respondent argued that historical data from exposed pipe reports showed little evidence
of corrosion or disbonded coating.23 Respondent asserted that these reports showed that Cypress
was receiving adequate cathodic protection and that Respondent was indeed considering IR
drop.
Evidence that the pipeline, at one time, was free of corrosion or coating damage at these specific
locations does not, alone, show that cathodic protection is currently adequate along the entire line
or that IR drop has been properly considered. Moreover, Respondent did not provide the
exposed pipe reports or any explanation of how it analyzed the report contents to conclude that
IR drop was fully considered. In the absence of such documentation and analyses, I reject
Respondent’s argument.
24 Pipe reports only offer a snapshot of select locations along this 104-mile pipeline.
Third, Respondent indicated that it considered soil resistivity to evaluate the electrical
characteristics of the pipe and environment.25 Respondent asserted that soil resistivity data from
exposed pipe reports and Respondent’s “knowledge of the right-of-way conditions indicate low
soil resistivity along the Cypress pipeline right-of-way.”26 Respondent concluded that its
evidence or analysis of how it concluded that soil resistivity was low. In the absence of such
evidence and analysis, OPS cannot assess what sort of data was collected or from what
location(s), whether the data was representative of resistivity elsewhere on the pipeline, and what
value it had in considering IR drop.
“knowledge” supported “a generally negligible IR.”27 However, Respondent provided no
21 Response at 5-6; Hearing Exhibit 4H.
22 See NACE STANDARD paragraph 6.3.3, “Absence of external corrosion damage or the halting of its growth may
indicate adequate external corrosion control. The [ILI] technique, however, may not be capable of detecting all
types of external corrosion damage, has limitations in its accuracy, and may report as anomalies items that are not
external corrosion. For example, longitudinal seam corrosion and general corrosion may not be readily detected by
in-line inspection. . . . The appropriate use of in-line inspection must be carefully considered.”
23 Response at 5. While Kinder Morgan’s Response indicated that the exposed pipe reports have indicated no
corrosion and well-bonded coating, during the hearing Respondent indicated that 170 of 175 reports from 1991
through 2006 gave no indication of corrosion or coating damage. Presumably, the remaining five reports did
provide some indication of corrosion or coating damage.
24 Id.
25 Id.
26 Id. at 6.
27 Id.



10
Fourth, Respondent indicated that it had reviewed the historical performance of its cathodic
protection system by reviewing pipe-to-soil potential readings from annual corrosion surveys.
Respondent indicated that this action, in combination with other considerations, showed that the
company had considered IR drop. Here, again, Kinder Morgan failed to explain or provide
documentation as to how its review of historical data showed that IR drop had been properly
considered. The survey data provided by Respondent showed only the measured pipe-to-soil
potentials, not whether or how IR drop had been measured.28
Finally, Respondent asserted that a lack of corrosion-related leaks on the Cypress system showed
that corrosion was being adequately addressed.
SFPP Pipeline, an absence of corrosion-related leaks may simply be more a matter of luck than
evidence of compliance with the regulation.
29 I disagree. As noted above in relation to the
In summary, while Respondent has taken some steps to consider IR drop, it has not satisfied the
NACE Standard or the regulation because its application of the Methods for considering IR drop
only focused on certain locations along the pipeline. This practice does not account for
differences in environmental and soil conditions, and the resulting differences in IR drop, that
could occur throughout the SFPP and Cypress systems. In addition, Respondent has not
provided evidence to support its arguments on exposed pipe reports or its knowledge of soil
resistivity.
Accordingly, based on the foregoing, I find that KM violated 49 C.F.R. § 195.573(a) by failing
to properly conduct tests on its cathodically protected SFPP and Cypress Pipeline systems.
Item 5: The Notice alleged that Respondent violated 49 C.F.R. § 195.579(a), which states:
§ 195.579 What must I do to mitigate internal corrosion?
(a) General. If you transport any hazardous liquid or carbon dioxide
that would corrode the pipeline, you must investigate the corrosive effect of
the hazardous liquid or carbon dioxide on the pipeline and take adequate
steps to mitigate internal corrosion.
The Notice alleged that KM violated 49 C.F.R. § 195.579(a) by failing to investigate the
corrosive effects of the hazardous liquid on its SFPP and Cypress systems.
Respondent denied the allegation, arguing that its past efforts satisfied the requirement that it
investigate the corrosive effect of hazardous liquid on its pipelines. KM contended that it had
tested its SFPP system in the early 1990s for internal corrosion, using Electric Resistance (ER)
probes.30
According to the company, such testing showed that corrosion rates were lower than
one mil per year on all ER probes, and that such data supported its decision to cease the use of all
28 See Hearing Exhibit 4G.
29 Response at 6.
30 Id.



11
ER probes in 1994.31 KM also argued that ILI runs had “supported a lack of internal corrosion”
in the SFPP system.32 Regarding the Cypress Pipeline, KM argued that its specifications for the
line prohibited any free water from entering the system.
33 KM also argued that a 2004 ILI of the
Cypress line revealed no indications of internal corrosion and that a coupon installed from 1994
to 1997 showed minimal corrosion rates.34 Respondent argued, therefore, that it did not
transport hazardous liquid that would corrode the Cypress Pipeline.35
I find Respondent’s argument unpersuasive. The current version of Part 195 of title 49, Code of
Federal Regulations, was established pursuant to the Hazardous Liquid Pipeline Safety Act of
1979 (Pub. L. 96-129)(Act). The purpose of the Act and the regulations promulgated thereunder
is to provide adequate protection against risks to life, property, and the environment posed by the
transportation of hazardous liquids. The regulations cover the design, construction, operation,
maintenance, and emergency response requirements for hazardous liquid pipeline facilities. A
major goal of the regulations is to ensure that pipeline operators prevent and control corrosion in
their pipeline systems, one of the major causes of pipeline failures. Operators transporting
hazardous liquid are obligated to recognize and address corrosion and to prevent corrosion-
related leaks and failures on their pipelines.
The phrase “hazardous liquid . . . that would corrode the pipeline,” as used in § 195.579(a), must
be construed in a manner that gives effect to the purpose and intent of the Act and the Part 195
regulations. The intent of this section is to prevent harmful leaks of hazardous liquid caused by
internal corrosion. To accomplish this objective, pipeline operators are required to monitor their
pipelines wherever internal corrosion could be present and to take appropriate actions to
minimize the corrosion in a manner that prevents leaks and other hazards. Known causes of
internal corrosion include certain materials commonly found in hazardous liquid pipeline
systems, including carbon dioxide, hydrogen sulfide, water, sediments, and microbes that can
cause or contribute to internal corrosion. Other factors may also serve to amplify the corrosive
effects of these materials, including low spots and locations where the hazardous liquid does not
have sufficient velocity to carry away water and sediments.
In this case, Respondent’s limited use of coupons and ER probes in the past demonstrated that
there was corrosion occurring on both the SFPP and Cypress systems, though apparently at a low
rate. Any number of changes or upsets in upstream processes, however, could introduce
corrosive materials into the hazardous liquid, despite KM’s routine procedures or any
specifications prohibiting the presence of water in the lines. Therefore, I find that KM transports
a hazardous liquid that would corrode the pipeline.
31 Id.
32 Id.
33 Id.
34 Id.
35 Id.



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Furthermore, even though corrosion rates on these two systems may have been low in the past,
this does not mean that KM may cease investigating the corrosive effects of the hazardous
liquids being transported. To account for potential changes or upsets, KM must investigate the
corrosive effects of the hazardous liquids transported in its pipelines on a continuing basis.
Respondent’s practice of ILI may be useful in detecting corrosion, but ILI alone is inadequate to
satisfy the regulation. ILI only gives a snapshot in time of the condition of the pipe. Corrosion
can occur in the years between ILI runs if water or other corrosive materials accumulate inside
the system. In addition, ILI of mainline pipe does not provide information on an entire pipeline
system because internal corrosion generally occurs first in dead- and intermittent-flow areas that
cannot typically accommodate ILI tools. In light of the possibility that water or other corrosive
materials may enter the pipeline systems at any time, I reject KM’s arguments that its past efforts
satisfied the requirements of the regulation.
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 195.579(a) by failing to investigate the corrosive effects of the hazardous liquid on its pipeline.
These findings of violation will be considered prior offenses in any subsequent enforcement
action taken against Respondent.
ASSESSMENT OF PENALTY
Under 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed
$100,000 per violation for each day of the violation, up to a maximum of $1,000,000 for any
related series of violations. In determining the amount of a civil penalty under 49 U.S.C.
§ 60122 and 49 C.F.R. § 190.225, I must consider the following criteria: the nature,
circumstances, and gravity of the violation, including adverse impact on the environment; the
degree of Respondent’s culpability; the history of Respondent’s prior offenses; 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 $35,000 for the violations cited above.
Item 1: The Notice proposed a civil penalty of $10,000 for Respondent’s violation of 49 C.F.R.
§ 195.406(b), for failing to have adequate controls and protective equipment to control the
pressure on its SFPP and Cypress Pipeline systems within the limits established under
§ 195.406(a). Adequate pressure controls and protective equipment are important to pipeline
safety because they serve to prevent pipeline overpressure and possible ruptures, spills, and harm
to life, property, and the environment. KM’s violation reduced the margin of safety provided by
the regulation.
Given the potential threat posed by inadequate pressure controls, I find that the gravity of the
violation supports the proposed penalty amount. In addition, the violation continued for a
substantial period yet the proposed penalty is far below the $100,000 per violation per day limit.
This amount reflects the fact that no pipeline failures or spills were associated with the violation.



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KM has not presented any other evidence or argument justifying a reduction or elimination of the
proposed penalty. Accordingly, having reviewed the record and considered the assessment
criteria, I assess Respondent a civil penalty of $10,000 for violation of 49 C.F.R. § 195.406(b).
Item 4: The Notice proposed a civil penalty of $25,000 for Respondent’s violation of 49 C.F.R.
§ 195.573(a), for failing to properly conduct annual tests on its cathodically protected SFPP and
Cypress Pipeline systems. As noted above, I found that KM failed to properly consider IR drop
when performing annual tests of its cathodic protection system. As a result, Respondent may not
have had an accurate understanding of the effectiveness of its cathodic protection system.
Inadequate cathodic protection may lead to external corrosion, which, in turn, can result in
pipeline leaks or failures. This violation continued for many days, which serves to increase the
gravity of the offense and the amount of the proposed penalty. In addition, the violation
continued for a substantial period yet the proposed penalty is far below the $100,000 per
violation per day limit. KM has not presented any other evidence or argument justifying a
reduction or elimination of the proposed penalty. Accordingly, having reviewed the record and
considered the assessment criteria, I assess Respondent a civil penalty of $25,000 for violation of
49 C.F.R. § 195.573(a).
In summary, having reviewed the record and considered the assessment criteria for each of the
Items cited above, I assess Respondent a total civil penalty of $35,000.
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 Divisi
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