# CYPRESS INTERSTATE PIPELINE LLC — Notice of Probable Violation

- **operation:** document
- **citation:** CPF 120045004
- **title:** CYPRESS INTERSTATE PIPELINE LLC — Notice of Probable Violation
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2004-07-15
- **effective on:** Not available
- **summary:** CLOSED notice of probable violation citing 195.452(b)(3), 195.452(c)(2), 195.452(d)(3)(ii), 195.452(e)(1)(i), 195.452(e)(1)(iii), 195.452(e)(1)(iv), 195.452(e)(1)(ix), 195.452(e)(1)(vii), 195.452(f)(3), 195.452(f)(4), 195.452(f)(8), 195.452(g), 195.452(h)(2), 195.452(i)(2), 195.452(j)(2).
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**body:**

Notice of Probable Violation involving CYPRESS INTERSTATE PIPELINE LLC. PHMSA's enforcement data identifies the cited regulations as 195.452(b)(3),  195.452(c)(2),  195.452(d)(3)(ii),  195.452(e)(1)(i),  195.452(e)(1)(iii),  195.452(e)(1)(iv),  195.452(e)(1)(ix),  195.452(e)(1)(vii),  195.452(f)(3),  195.452(f)(4),  195.452(f)(8),  195.452(g),  195.452(h)(2),  195.452(i)(2),  195.452(j)(2). The case was opened on 2004-07-15 and is reported as closed as of 2008-12-30. Proposed civil penalty: $325,000. Assessed civil penalty: $325,000. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

120045004_Final Order_06262006.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120045004/120045004_Final%20Order_06262006.pdf

120045004_final order_06262006_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120045004/120045004_final%20order_06262006_text.pdf

CPF_1-2004-5004.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120045004/CPF_1-2004-5004.pdf

CPF_NO_1-2004-5004(2).pdf: https://primis.phmsa.dot.gov/enforcement-documents/120045004/CPF_NO_1-2004-5004(2).pdf

CPF_NO_1-2004-5004.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120045004/CPF_NO_1-2004-5004.pdf

120045004_final order_06262006_text.pdf

U S. Deportment
Qt Tronsportotlon
Pipetine and
Haxardau» Naferfat» Safety
Admi ni»tration
JUN 36 2:o
%fr Jerry Mifhorn
V ice President of Operattons
Ktndcr lv$or~an Enerv& Partner~ I P
500 Dallas Street. Suite 1000
Houston, TX 77002
Rc: CPF No, 1-2004-5004
Dear Mr, Milhorn.
Enclosed is the Final Otder ~ssued b~ the Associate Admtntstrator fcr Pipcltne Safety n
tftc above-referenced case. ft makes findings of vtofatton, as»esses a clktf penalty of
$325. 000, and specifies acttons to be taken to comply vrith the p&pefine safety regufat&ons
I he pcrtaft) payntent terms are set forth in tlte F}naf Order KVhen tf)e ctvil penafty ts pard anJ
the terms of the Compliance Order are completed, as determined by the Director, Eastern
Region, this enforcement action off be closed Your receipt of'thc I:inal Order constitutes
service of that document under 4') C. F, R. ) 190 5
James Reynolds
Ptpef&ne Compfjance Regis',
OfHce of Pipeltnc Safety
I tie los ure
cc 9 tlham Gute. Director. Eastern Regon
( I;RTII'IL~A WML — RK I 4! RN RECEIPT RK UK& I"F0



DEPARTiiiIENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADAIINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, D. C. 20590
In the Matter of
Kinder Morgan
Energy Partners, L. P.
,
Respondent
CPF No. 1-2004-5004
FINAL ORDER
Dunng the weeks of April 7. April 21, and June 23, 2003. pursuant to 49 U. S. C & 60117.
representatives of the Pipelme and Hazardous Materials Safety Administration, Office of
Pipeline Safety (OPS) conducted an inspection of Respondent's integrity management program
at its facilities in Orange California and Doraville, Georgia. As a result of the inspection. the
Director, Eastern Region, OPS, issued to Respondent, by letter dated July 15, 2004. a Notice ot
Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (Notice) In
accordance with 49 C. F. R. ( 190. 207, the Notice proposed iinding that Respondent had
committed violations of 49 C. F. R. Part ] 95, and proposed assessing a civil penalty of $325, 000
for the alleged violations, The Notice also proposed ordering Respondent to take certain
measures to correct the alleged violations.
Respondent responded to the Notice by letter dated August 16, 2004 (Response). Respondent
contested many of the allegations in the Notice and requested a hearing. The hearing was held
on April 12-13, 2005 in Washington, DC, AAer this hearing, Respondent provided additional
information for the record on May 12, 2005.
FINDINGS F 4'IOLATION
Item I in the Notice alleged that Respondent violated 49 C, F R. II 195. 452(b)(3) by failing to
include provisions in its baseline assessment plan (BAP) to account for and address the
susceptibility of its pre-1970 low-frequency ERW piping to seam failures and the potential of its
piping for stress corrosion crackmg (SCC) in the absence of sound technical Justificattons for
discounting these risk factors. The integnty management program (IMP) regulations require
pipeline operators to identify and assess the risks associated with operating their pipehnes that. in
the event of a failure. could affect a high consequence area (HCA) In order to conduct a
meaningful risk analysis, a pipeline operator must accurately represent all of thc risks on a given
pipeline in its chosen risk model including assigning the appropriate weight to each risk factor
relative to other risk factors so that thc pipeline segments that pose the highest nsk to HCAs can
be appropnately priontized.



With respect to the ERW pipe issue, it has been commonly known throughout the pipeline
industry for many years that pipelines constructed before 1970 using low-frequency ERW
longitudinal seams and lap welded pipe are susceptible to scam failures. Based on htstoncal
pertormance, ERW and lap-welded pipe is susceptible to seam failure and presents a higher risk
of failure than other pipe, all other factors being equal. Moreover, thc pipeline safety regulations
expressly deem all pre-1970 ERW pipe to be presumptively susceptible to seam failure.
Therefore, the presence of pre-1970 ERW pipe is a significant risk factor and seam I'ailure is a
failure mode that operators of ERW pipe must fully address in their nsk analyses. In this case„
seam failures on some of the actual ERW pipe in Respondent's Santa Fe Pacific Pipeline (SFPP)
ivere documented in OPS Techmcal Report 89-1
In its response and at the hearing, Respondent acknowledged that the susceptibility of pre-1970
low frequency ERW pipe to seam failures was known industry-wide as a significant rtsk.
Respondent, however. contested the allegation that it failed to adequately address the presence ot
ERW pipe in its pipeline system in its IMP plan. In connection with the hearing. Respondent
produced a memorandum that purported to establish that it had replaced the ERW pipe it
believed to be susceptible to seam failure. The memorandum noted that "about a mile of the
Richmond-Oakland 8-inch immediately downstream of Richmond Station and about 3. 5 miles of
the 10-mch San Diego Line through Tustin" had been replaced. Notably, however, the study did
not document why only those small sections of ERW pipe were deemed to be high risk and the
rest of the ERW ptpe in its system was not. Respondent also asserted that all of the remaining
ERW pipe in its SFPP was subJect to operating restrictions. OPS correctly pointed out. however.
that while the SFPP is a significant part of the Respondent's system it only represents about 25
percent of the total mileage of Respondent's pipeline system to which its IMP applies. The
assessment of pipelines that are susceptible to seam failures that could affect a HCA is a
requirement for all such pipelines. Respondent made no assertion that similar reviews had been
conducted for its other pipel ines.
OPS issued Alert Notices on January 28, 1988 and March 8, 1989 mforming pipelme operators that low-
t'requency ERW pipe was sub)ect to longitudinal iield seam failures caused by the presence of manufactunng
defects in thc F RW seams that can grow over time Seam corrosion and cychc fatigue have been found to have
contributed to the growth of these defects and in some cases, operational failures have occurred many months or
years after successful hydrostatic testing was conducted. Thts is also retlected in subsequent rules For example. the
preamble that accompamed publication of the rule estabtishmg a risk-based alternative to pressure testing, as
follows "Pre-1970 electnc resistance welded (ERW) and lap welded pipelmes susceptible to longitudinal seam
failures exhibit the highest potential nsk because of their combination of probabihty of failure and potential for
larger volume releases as evidenced by histoncal records" (63 FR 59475 Nov 4, 1998)
49 C F R ti 195 303(d)
"FRW Summary for Liquid and Gas Transmission Lmes. " (1989) At the time, this pipehne ivas known as the
Southern Pacilic Pipelme
Dunng thc 2003 inspection Respondent apparently did not present the SFPP study The memorandum provided
by Respondent descnbmg the study made the followmg single qualitative generahzation 'a targe portion of the pipe
purchased by SPPL in the mid to late 1960's was manufactured ai Kaiser's Fontana mill using modern techmques
and is of good quality. " (Letter from Engelhardt to DesBarres, Sept 8, 1989)



Respondent also asserted that its subject matter experts (SMEs) had concluded that its pipe was
not susceptible to seam failure. At the time of the inspection, however, Respondent presented no
seam analysis or other documentation demonstrating that a thorough engineering or metallurgical
analysis on the susceptibility of its ERW pipe to seam failures had been conducted. Moreover. at
the time of the inspection, Respondent's "Bass Trigon" computer risk model reflected
Respondent's apparent lack of information about the type ot longitudinal seam for many
segments of its pipeline system. The data used for the seam type for a significant number of
pipeline segments in the risk model were listed as "unknown"
Respondent also argued that there was a lack of industry guidance for how to perform an
engineering analysis to determine the susceptibility of particular ERW pipe to seam failures.
OPS, however, pointed out that guidance was available for performing ERW analysis. To take
Just one example. Dr. John Kiefner published a methodology for conducting such an analysis in a
paper presented on February 2-6, 2002 at the ASME Engineering Technology Conference on
Energy, entitled "Dealing With Low-Frequency-Welded ERW Pipe and Flashwelded Pipe With
Respect To HCA-Related Integrity Assessments. " While pipeline operators are not required to
follow Dr. Ktefner's methodology, the availability of his methodology is sufficient to establish
that industry guidance for conducting an engineering analysis to determine the susceptibility of
ERW pipe to seam failure was available to Respondent in advance of the inspection. '
Respondent further asserted that in-line electromagnetic acoustic transducer (EMAT) inspection
tools capable of detecting seam defects were only just becoming commercially available at the
time of the inspection. This assertion, however, is not relevant to the merits of thc allegation.
Respondent was cited tor failing to identify wluch of its lines are susceptible to seam failure and
to schedule an assessment for those lines. Even if the EMAT technology was not available at the
time, other methods were available by which to conduct integrity assessments for seam defects
including hydrostatic pressure test, ultrasonic in-line crack detection tools. and transverse flux
magnetic flux leakage in-line crack detection tools. Respondent was aware of other technologies
available for conducting assessments tor cracks and seam defects.
Finally, we note that one of the key technical factors in determining susceptibility to seam failure
ts the degree of cyclic loading experienced by a given line. Pressure cycling promotes defect
growth and can contribute to eventual failure. Respondent, like many other hazardous liquid
pipeline operators, performs batch operations on its mainlines and delivery lines which typically
generates frequent pressure cycling. Absent a strong technical justification to the contrary, any
ERW line operated under these circumstances should be considered susceptible to seam failure.
and assessment methods must be selected accordingly. In a system of approximately 10. 000
miles of pipelines, composed of numerous older legacy systems subject to frequent pressure
cycling, Respondent's claim that it had no segments considered susceptible to seam failure was
unpersuasive. Overall. Respondent failed to demonstrate that its decision to exclude the
Respondent stated that it subsequently adopted an updated procedure based on the Baker study entitled ' Lotv
Frequency ERW and Lap Welded Longitudinal Seam Evaluanon Final Report" (Oct 2003), and Respondent
emphasized that this report was issued after thc OPS mspection The Baker study however, wai conducted m
association with Dr. Kiefner, and the suscepnbility analysis described m the Baker study is only a slightly updated
version of the analysis methodology Dr Kiefer presented to ASME in February 2002, as discussed aboie.



susceptibility of its ERW pipe to seam failures as a significant factor in its risk analysis was
justified by sound technical analysis during the relevant time period.
With respect to stress corrosion cracking (SCC), Respondent acknowledged that SCC was a risk
on pipelines, but argued that because it had never expenenced a "known" SCC failure prior to
the inspection it was justifie in discounting SCC as a significant factor in its risk model OPS
pointed out that prior to the mid-1990s, Respondent had been to some degree mcffcctive in its
determination of the causes of pipeline accidents to thc point that OPS had cited and levied a
civil penalty and compliance order against Respondent in 1994 — in part for its failure to
ascertain the causes of pipeline accidents. Therefore, it is possible that past accidents could have
been caused by SCC, but were undiagnosed because there is reason to believe that Respondent
did not effectively determine the true cause of many historical accidents. In addition,
Respondent built its extensive network of pipelines through acquisitions In order Ior
Respondent to defend this assertion, it would have needed to present a rigorous review of the
historical pipeline accidents on its legacy systems that occurred during previous ownership.
Therefore, while Respondent may not have previously attributed a pipeline failure to SCC, this is
not the same thing as saying Respondent had no reason to consider SCC to be a potential risk
tactor. Absent metallurgical reports on all past failures, Respondent's statement that its systems
have never experienced a SCC-related failure is inconclusive at best.
Respondent also argued that it did not believe that the IMP rule contemplated the consideration
of SCC as a threat to hazardous liquid pipelines at all. This argument, however. is unpersuasive.
Published guidance for implementation of the rule in Appendix C to 49 C. F. R. Part 195
explicitly lists SCC as a threat to be assessed with crack detection in-line inspection (II I) tools
In addition. the preamble to the IMP rule (65 FR 75396) specifically addresses crack detection
and SCC in the BAP as follows:
Mrat Must Be in the Baseline Assessmerrt Plan? Section l95 452(c)
Crack Detection: Since the early 1 990 's, pipeline operators liai'e successfirlly
field tested intenial inspection tools capable of nondestructii ely ideirtifying
fatigue cracks and stress corrosioir crackrn in the longitudiiial seam. Researclr
arid dei'elopmeiit coiitiniies on these tools to strii e for reliable ide&iti ficatrorr of
otliei types of seanr defects, such as hook cracks IVitlr the use of ultrasonic and
MFL (trans' erse orientation) technology, pipeline segments that hai e
e~perrerrced fatigue cracking can now be iirspected. Cracks w itlr a potential to
rupture can be ideiitified and repaired prior to groiiing to a critical stage. Tlris is
particrdarly important as this type of defect coiild suri ive iiritial and subsequerrt
pressure tests but their ~'ith pressure cychng, groN oi er time to a critical stage
and leak or ruptiire (emphasis added j.
This put pipeline operators on notice that the intent of the rule language requiring operators to
develop and tollow IMP plans was for BAPs to include assessments to address the nsks of crack
defects — including SCC because of its particular importance. Finally. Respondent cited OPS
Advisory Bulletin ADB 03-05 in an attempt to justify its assertion that the rule did not



contemplate consideration of the SCC threat. It is clear from the text of the IMP rule however,
that the rule did not specifically focus on any particular threat because it was intended that
operators address all threats. Therefore, while Respondent correctly points out that this advisory
bulletin was not issued until after the inspection, it merely notes that the rule did not specify
SCC.
Respondent also suggested that there was no techiucal guidance in place at the time of the
inspection for industry or OPS inspectors to use in evaluating SCC threats. OPS, however,
potnted out that numerous reference and research reports pertaining to SCC threats to pipelines
had been published by the time Respondent was developing its BAP. The Baker Report, for
example, compiled many references to SCC dating back to the 1970's. Some of the more
important reports highlighted by Baker include:
~ "Report of the Inquiry [on] Stress Corrosion Cracking on Canadian Oil and Gas
Pipelines" by the Canadian National Energy Board (NEB 1996).
~ "Stress Corrosion Cracking — Recommended Practices' published by the Canadian
Energy Pipeline Association (CEPA 1997a). Baker noted that "[t]he document presents
an excellent model for pipeline operators who are setting up procedures for preventing
controlling and mitigating external SCC. "
~ CEPA produced an additional report that specifically addresses circumferential SCC.
a less common form of SCC (CEPA 1997b). Thts report documents the expenences of
NOVA Gas Transmission Ltd.
,
Northwestern Limited, Federated Pipe Lines Ltd. , and the
SNAM system in Italy in investigating and mitigating leaks due to circumferential SCC.
Subsequently, CEPA issued an addendum to the Stress Corrosion Cracking—
Recommended Practices addressing circumferential SCC (CEPA 1998),
~ "Protocol to Prioritize Sites for High pH Stress-Corrosion Cracking on Gas
Pipelines", Eiber and Leis (1998). In this report, Eiber and Leis document the
development of a simple form for evaluating the susceptibility of a pipeline segment to
high pH SCC An example of an SCC integrity management plan is also presented. This
document provides good descriptions of the variables that are considered for determining
the degree of susceptibility of a pipeline to high pH SCC and presents summary level
supporting historical data.
Therefore. Respondent's suggestion that there was no guidance available to industry by which to
evaluate, assess, and manage thc threat ot SCC is unfounded.
Respondent then argued that its IMP did address SCC because one paragraph in Section F3. 5
referenced SCC. Although Respondent's program description demonstrates that it was aware of
the factors that influence SCC risk as reflected in API-1160, compliance with the rule requires
more than a brief description of what should be done. The IMP rule requires that operators
implement and follow the program elements at each stage. Simply put, Respondent did not
' Stress Corrosion Cracking Study with Database, i=tnal Report. " Michael Baker Jr, Inc (Jan 2005) Whde the
Baker report did not preceed the inspection. it did not document any new techtucal research. or develop any new
guidance for handlmg SCC. Rather, the Baker report was a compendium and summary of existing research and
guidance already available to industry assembled into one convenient source.



6
analyze for SCC in prtoritiztng its segments for baseline assessments. To the contrary. it decided
to turn off the following known risk factors for SCC in its computer risk model: age of pipe; type
of coating; CP system conditions and levels; soil stresses; drainage type: degree of pressure
cyclmg: excavation data; and fracture mechanics analysis.
Respondent further asserted that its program was literally identical to API-1160. As a factual
matter this is incorrect. For example, the only basis offered by Respondent for turning off the
SCC risk factor was a lack of known failures — but failure history is not listed in API-1160 as a
consideration when analyzing SCC risk attributes. API-1160 includes a number of guidance
statements on SCC including:
~ AP 1-1160 indicates that SCC mspections should only be suspended or postponed after
two consecutive assessments in which no new SCC sites were discovered (Section 9. 4, 2).
This guideline was not in Respondent's program (indeed they did not include any SCC
assessments in their plan as of March 2003).
~ API-1160 identifies continued hydrostatic testing to account for crack growth.
including SCC specifically (Section 9. 5. 2). This guideline was not reflected in
Respondent's program.
API-1160 cautions that SCC may be present for many years before causing problems
(Section A. 1. 6. 3). This is why past failure history alone is not a good enough indicator of
SCC risk to be the sole reason for discounting it.
None of these guidelines were reflected in Respondent's BAP. Therel'ore, Respondent's written
program was not identical to API-1160, much less implemented in accordance with the standard.
In fact. as noted above Respondent decided to turn off every risk factor in Respondent's Section
F3. 5 that corresponded to API-1160 in its risk analysis computer model. Finally. it should be
noted that AP1-1160, Section 8. 4, "Characteristics of a Sound Risk Assessment Approach"
explicitly states that:
"rf risl- assessment shottld be investigative in nature, seehng to identify
pret iously unrecogni "ed rhreats to pipeline integrity. It should mal e use of
pretiotts ei enis, bur focus on rite potential for fitture mishaps, inchiding sceiiarios
thar may net er ltave liappened before. "
The IMP rule requires pipeline operators to follow recognized industry practices in carrying out
their IMP programs unless the operator can demonstrate that an alternative practice is supported
by a rehable engineering evaluation. Respondent's approach reflected a reluctance to take an
investigative approach to the identification of threats in order to avert pipeline accidents,
including those caused by previously unrecognized threats to the pipeline.
Accordingly, I tind that Respondent violated tl 195. 452(b)(3) by failing to include provisions in
its BAP to account for and address the susceptibility of its pre-1970 low-frequency ERW piping
49 C F R tl 195 452{b){6) Whtle API- I 160 +as not formally incorporated by reference mto 49 CI. R Part 195 at
the time the IMP rule was issued, it still serves as evidence of the generally accepted industry practice tor pipelme
integrity management programs



to seam failures and the potential of its piping for SCC in the absence ot sound technical
gustifications to discount these risk factors.
Item 2a in the Notice alleged that Respondent violated 49 C. F. R. It 195. 452(e)(1)(i) by failing to
consider the results of previous integrity assessments including previously identified defect type
and predicted growth rate in establishing an integrity assessment schedule prioritizing its pipeline
segments by risk Section 195. 452(e) requires a pipeline operator to base its assessment schedule
on all risk factors that reflect the risk conditions on each segment and list several such factors
includmg previous integrity assessments
In its response and at the hearing, Respondent acknowledged that it decided not to activate the
capability of its computer model to analyze previous mtegrity assessments, but contended that it
used qualitative evaluation by its SMEs to evaluate those risk factors that it chose to turn off in
the computer model. After Respondent made this argument, OPS pointed out that Respondent s
risk ranking exactly matched the ranking produced by the computer model alone. OPS further
noted that because the omitted nsk factors were of such importance, it is implausible that any
thorough SME analysis of these omitted factors would have zero influence on the resulting nsk
ranking. Moreover, the number of data elements listed in the matrices in Respondent's own
exhibits that its SME s would have had to collect and analyze for a 10, 000 mile pipeline system
would have taken a significant period of time to conduct systematically and thoroughly and
would have generated large volumes of decision making information and technical analysis
documentation that Respondent would have been required by regulation to maintain. "
Respondent did not present any such documentation. Therefore, even if Respondent's SMEs
contributed to the process to one extent or another, Respondent failed to demonstrate that the
resultmg nsk analysis considered previous integrity assessments in a manner that permitted a
meanmgful risk rankrng. Accordingly, 1 find that Respondent violated ) 195. 452(e)(1)(i) by
failing to consider the results of previous integnty assessments including previously identified
defect type and predicted growth rate in establislung its integrity assessment schedule.
Item 2b in the Notice alleged that Respondent violated 49 C. F. R. $ 195. 452(e)(1)(i») by failing
to consider repair history in establishing an integrity assessment schedule prioritizing its pipeline
segments by risk. Respondent offered the same response to tlus item as for Item 2a above. For
reasons already discussed, Respondent was unable to refute the allegation. Accordingly, I find
that Respondent violated g 195. 452(e)(1)(iii) by failing to consider repair history in establishing
its integnty assessment schedule.
Item 2c in the Notice alleged that Respondent violated 49 C. F. R. ( 195, 452(e)(1)(vii) by failing
to consider local environmental factors, including soil corrosivity, subsidence, climactic
conditions, and geo-technical hazards, in establishmg an integrity assessment schedule
prioritizing its pipeline segments by risk. Respondent offered the same response to this item as
t'or Item 2a above For reasons already discussed. Respondent was unable to refute the
allegation. Accordingly, I find that Respondent violated $ 195. 452(c)( I )(vii) by failing to
consider local environmental factors including soil corrosivity, subsidence, climactic conditions.
and geo-technical hazards in establishing its integrity assessment schedule.
49 C. F R g 195 45'2(l)



Item 2d in the Notice alleged that Respondent violated 49 C. F. R. $ 195 452(e)(1)(ix) by failing
to consider physical support of a segment such as by a cable suspension bridge in establishing an
integrity assessment schedule prioritizing its pipeline segments by risk. Respondent offered the
same response to this item as for Item 2a above. For reasons already discussed, Respondent was
unable to refute the allegation. For reasons already discussed. this argument was unpersuasive.
Accordingly. 1 find that Respondent violated ) 195. 452(e)(1)(ix) by failing to consider physical
support of a segment such as by a cable suspension bridge in establishing its integrity assessment
schedule.
Item 3a in the Notice alleged that Respondent violated 49 C. F. R. ) 195. 452(i)(2) by failing to
maintain documentation demonstrating that the risk model it used to identify the need for
preventative and mitigative measures to protect the HCAs weighted and scored all of the relevant
risk factors in a manner permitting a meaningful risk analysis of its system. Respondent did not
contest this allegation. Accordingly, 1 find that Respondent violated ) 195. 452(i)(2), as more
fully described in the Notice.
Item 3b in the Notice alleged that Respondent violated 49 C. F. R. ) 195. 452(i)(2) by tailing to
demonstrate that weight assigned to product type by the risk model it used to identi1'y the need
tor preventative and mitigative measures was justified given Respondent's actual operating
experience. Specifically, the Notice alleged that in some cases product type was weighted as
much as 2:1 versus all other risk factors combined. OPS contended that because product type is
most strongly associated with internal corrosion risk. Respondent's decision to assign this level
of weight to product type distorted its nsk analysis by overwhelming the risk weighting for other
nsk factors actually identified as the cause ofhistorical failures on Respondent's system. such as
factors associated with external corrosion, third-party damage, or seam failures
ln its response and at the hearing, Respondent insisted that the weight it assigned to product type
was appropriate. OPS, however, showed that over the period from 1998 to 20Q3. while
Respondent's pipelines experienced a number of failures, in no mstance was the primary cause
determined to be internal corrosion. The integrity management regulations do not prescribe the
weight to be assigned!o any single risk factor. A pipeline operator, however. is obligated to
weigh all of the relevant risk factors in a manner permitting a meaningful risk analysis of its
particular system. Respondent failed to demonstrate that the weight it decided to assign to
product type permitted a meaningful risk analysis given the historical causes of failures that
actually occurred on its system. Accordingly, 1 find that Respondent violated $ 195. 452(i)(2) by
tailing to demonstrate that the weight assigned to product type by the risk model it used to
identify thc need for preventative and mitigative measures was justified given Respondent's
actual operating experience.
Item 3c in the Notice alleged that Respondent violated 49 C. F. R ) 195. 452(i)(2) by failing to
demonstrate that the weights assigned to the HCA risk factors by the risk model it used to
identify the need for preventative and mitigative measures was based on the relative risk
relationships among those factors. Respondent did not contest this allegation, Accordingly. 1
find that Respondent violated ) 195. 452(i)(2), as more fully described in the Notice.



Item 3d in the Notice alleged that Respondent violated 49 C. F. R. ( 195. 452(i)(2) by fail»g «
demonstrate that the weight assigned to segment length by the risk model it used to identify the
need for preventative and mitigative measures was justified given Respondent's actual operating
experience. Specifically, the Notice alleged that, with respect to the 212 ranked segments for the
Western/Midcon area. the average length of the 25 highest ranked segments was 1. 54 miles
while the average length of the 25 lowest ranked segments was 54, 97 miles and that nothing in
Respondent's operating history supported this scoring method.
ln its response and at the hearing, Respondent insisted that the weight it assigned to segment
lenl~h was appropriate, OPS acknowledged that shorter lines can be in more populated areas,
but pointed out that longer lmes affect many HCAs where shorter lines affect few of them.
Moreover, Respondent was unable to establish as a factual matter that its spill history supported
its assertton that the shorter segments were at higher risk of failure. The integrity management
regulations do not prescribe the weight to be assigned to any single risk factor, A pipel»c
operator. however, is obligated to weigh all of the relevant risk factors in a manner permitting a
meaningful risk analysis of its particular system. Respondent failed to demonstrate that the
weight it decided to assign to segment length permitted a meaningful risk analysis given the
history of spills that actually occurred on its system. Accordingly, I find that Respondent
violated ) 195. 452(i)(2) by failing to demonstrate that the weight assigned to segment length by
the risk model it used to identify the need for preventative and mitigative measures was justified
given Respondent's actual operating experience.
Item 4 in the Notice alleged that Respondent violated 49 C. F. R. ) 195. 452(f)(3) by failing to
integrate available information concerning the age of in-line inspections and hydrostatic pressure
tests into its integrity management analysis. In its response and at the hearing. Respondent
acknowledged that its analysis did not differentiate prior assessments by age but argued that the
integrity management regulations were "silent" on whether differentiation of prior assessments
by age was required. This argument, however, is unpersuasive. The integrity management
regulations expressly require that operators consider the results of previous integrity assessments
such as defect type and size, and defect growth rate. lt appears that for a system as large as
Respondent's, OPS was willing to allow the age of previous assessments to serve as a kind ot
proxy for the true conditions of each pipeline (based on the presumption that all previous
assessments resulted in the identification and repair of all significant pipeline defects identified).
Pipelines recently assessed could therefore be presumed to be in relatively sound condition
However, for older assessments, there is less assurance that the line remains in sound condition.
Scoring all hnes that had ever been assessed equally does not acknowledge the reality that lines
that have not been assessed in a long time are much more likely to have integrity-threatening
defects than lines which were assessed and repaired recently. Because Respondent only
considered whether it had or had not conducted an assessment but failed to consider the results ot
the previous assessments, the actual condition of the line discovered during thc previous
assessment was not captured. Respondent not only failed to analyze the results ot past
assessments as required by the rule. but did not even use age differentiation to approximate this
required risk factor in its analysis.



10
Respondent also suggested that no guidance on this issue was made available. However.
Appendix C to 49 C. F. R. Part 195 speci tically guides the operator to consider "Date of pig run"
in one of the hypothetical models. Moreover, as was noted previously the IMP rule directs
operators to follow recognized industry practices in carrying out the integrity management
requirements. API 1160 Section 8. 8 stresses the importance of incorporating the results of
previous integrity assessments into the 'likelihood of failure" estimation. Accordingly. I find
that Respondent violated P 195. 452(f)(3) by faihng to integrate available information concernmg
the age of previously conducted assessments into its integrity management analysis.
Item 5 in the Notice alleged that Respondent violated 49 C. F. R. $ 195, 452(g) by failing to use
available pipeline data as inputs in its information analysis including basic information on seam
design block valve rating, maximum expected discharge pressure, and internal corrosion
inhibitor. At the hearing, Respondent acknowledged that the integrity management program
documentation provided to OPS at the time of the inspection did not demonstrate that the
specified data sets were reflected in its integrity management program. Respondent did provide
additional data tabulation materials in connection with the hearing rellecting modifications that
were subsequently made to its program, but this material was for a different set of line segments
and Respondent was unable to establish that this material represented the data tabulation
practices Respondent had in place at the time of the inspection. ' Therefore. Respondent failed
to demonstrate that it considered the results of previous integrity assessments in a manner
permitting a meaningful risk analysis during the relevant time period. Accordingly, I tind that
Respondent violated ( 195. 452(g) by failing to use available pipehne data as inputs in its
information analysis.
Item 6 in the Notice alleged that Respondent violated 49 C. F. R. ) 195. 452(e)(1)(iv) by failing to
include eleven specified HCA line sections containing hazardous liquids in its BAP. Respondent
did not contest this allegation. Accordingly, I find that Respondent violated ) 195. 452(e)(1)(iv)
as more fully described in the Notice.
Item 7 in the Notice alleged that Respondent violated 49 C. F. R. ) 195. 452(d)(3)(ii) by failing to
incorporate new HCAs or new information about existing HCAs into its BAP within one year
from the date the areas were identified. Respondent did not contest this allegation. Accordingly.
I find that Respondent violated tI 195. 452(d)(3)(ii) as more fully described in the Notice
These findings of violation will be considered prior offenses in any subsequent enforcement
action taken against Respondent.
See footnote 7
10 We make no determmation here as to tvhether these additional documents ~ere suNctent to iubiequentlp
estabhsh compliance,



11
ASSESS%1ENT OF PENALT
Under 49 U. S. C. g 60122, Respondent is subject to a civil penalty not to exceed $100, 000 per
violation for each day of the violation up to a maximum of $1, 000. 000 for a related series of
violations.
49 U. S. C. 1) 60122 and 49 C. F. R, $ 190. 225 require that. in determining the amount ot the civil
penalty. I consider the following criteria: nature, circumstances. and gravity of the violation.
degree of Respondent's culpability. history of Respondent's prior offenses, Respondent's ability
to pay the penalty, good faith by Respondent m attempting to achieve compliance, the effect on
Respondent s ability to continue in business, and such other matters as ]ustice may require.
With respect to Item I. the Notice proposed a civil penalty of $100, 000 for Respondent's failure
to include provisions in its BAP to account for and address the susceptibility of its prc-1970 low-
frequency ERW piping to seam failures and the potential of its piping for SCC in the absence of
sound technical justifications for discounting these risk factors. The safety of the public depends
on pipeline operators maintaining the integrity of their pipelines. Conducting an effective risk
analysis is a key step in order for pipeline operators to prioritize the integrity assessment of the
highest risk segments of their pipelines. If the risk analysis is not properly conducted at the
baselme assessment stage, it can adversely affect an operator's entire IMP program.
In its response and at the hearing, Respondent contended that the IMP rule only required that it
have a "fratnework" program and that the issues cited by OPS are merely improvements that it
had intended to develop over time. This argument, however, is unpersuasive. The IMP rule
expressly required that pipeline operators have the specified program elements in place by March
31, 2002. " Although continual evolution of IMP plans is certainly contemplated by thc IMP
rule (indeed, operators are required to update their programs as new data is acquired). when
required program elements such as prioritization of baseline assessments by risk were due to be
implemented. an operator's process for doing so must be mature, and nothing in the record
warrants concluding otherwise. In this case. all of the citations arose trom Respondent's
omission of required program elements or lack of technical justification for program
methodologies,
Respondent also questioned the adequacy of notice of how OPS intended to interpret and enforce
the IMP rule. The history of the IMP rule, however. demonstrates that OPS went to great lengths
to provide operators with pre-enforcement guidance on how it would interpret and apply the
requirements of the IMP rule including holding public meetings, developing a extensive IMP
websites. publishing detailed frequently asked questions (FAQs), and even publishing the
inspection protocols later used by OPS in conductmg IMP compliance inspections. For example.
OPS pointed out that the need to assess lines for the risk of cracks including SCC was
emphasized during a 2002 Workshop attended bv Respondent s personnel in which crack tools
were specifically listed as assessment methods. ' Respondent has presented no information that
49 C F. R t, 195 452(b)(1)
See 66 FR 35319 and 67 FR 31399 for more information on the IMP iiorkshopi



12
would warrant a reduction in the civil penalty amount proposed in the Notice for this violation.
Accordingly, having reviewed the record and considered the assessment criteria, I assess
Respon
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