{"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":null,"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).","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-120045004.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-120045004.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-120045004","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/120045004","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: $325,000. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n120045004_Final Order_06262006.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120045004/120045004_Final%20Order_06262006.pdf\n\n120045004_final order_06262006_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120045004/120045004_final%20order_06262006_text.pdf\n\nCPF_1-2004-5004.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120045004/CPF_1-2004-5004.pdf\n\nCPF_NO_1-2004-5004(2).pdf: https://primis.phmsa.dot.gov/enforcement-documents/120045004/CPF_NO_1-2004-5004(2).pdf\n\nCPF_NO_1-2004-5004.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120045004/CPF_NO_1-2004-5004.pdf\n\n120045004_final order_06262006_text.pdf\n\nU S. Deportment\nQt Tronsportotlon\nPipetine and\nHaxardau» Naferfat» Safety\nAdmi ni»tration\nJUN 36 2:o\n%fr Jerry Mifhorn\nV ice President of Operattons\nKtndcr lv$or~an Enerv& Partner~ I P\n500 Dallas Street. Suite 1000\nHouston, TX 77002\nRc: CPF No, 1-2004-5004\nDear Mr, Milhorn.\nEnclosed is the Final Otder ~ssued b~ the Associate Admtntstrator fcr Pipcltne Safety n\ntftc above-referenced case. ft makes findings of vtofatton, as»esses a clktf penalty of\n$325. 000, and specifies acttons to be taken to comply vrith the p&pefine safety regufat&ons\nI he pcrtaft) payntent terms are set forth in tlte F}naf Order KVhen tf)e ctvil penafty ts pard anJ\nthe terms of the Compliance Order are completed, as determined by the Director, Eastern\nRegion, this enforcement action off be closed Your receipt of'thc I:inal Order constitutes\nservice of that document under 4') C. F, R. ) 190 5\nJames Reynolds\nPtpef&ne Compfjance Regis',\nOfHce of Pipeltnc Safety\nI tie los ure\ncc 9 tlham Gute. Director. Eastern Regon\n( I;RTII'IL~A WML — RK I 4! RN RECEIPT RK UK& I\"F0\n\n\n\nDEPARTiiiIENT OF TRANSPORTATION\nPIPELINE AND HAZARDOUS MATERIALS SAFETY ADAIINISTRATION\nOFFICE OF PIPELINE SAFETY\nWASHINGTON, D. C. 20590\nIn the Matter of\nKinder Morgan\nEnergy Partners, L. P.\n,\nRespondent\nCPF No. 1-2004-5004\nFINAL ORDER\nDunng the weeks of April 7. April 21, and June 23, 2003. pursuant to 49 U. S. C & 60117.\nrepresentatives of the Pipelme and Hazardous Materials Safety Administration, Office of\nPipeline Safety (OPS) conducted an inspection of Respondent's integrity management program\nat its facilities in Orange California and Doraville, Georgia. As a result of the inspection. the\nDirector, Eastern Region, OPS, issued to Respondent, by letter dated July 15, 2004. a Notice ot\nProbable Violation, Proposed Civil Penalty, and Proposed Compliance Order (Notice) In\naccordance with 49 C. F. R. ( 190. 207, the Notice proposed iinding that Respondent had\ncommitted violations of 49 C. F. R. Part ] 95, and proposed assessing a civil penalty of $325, 000\nfor the alleged violations, The Notice also proposed ordering Respondent to take certain\nmeasures to correct the alleged violations.\nRespondent responded to the Notice by letter dated August 16, 2004 (Response). Respondent\ncontested many of the allegations in the Notice and requested a hearing. The hearing was held\non April 12-13, 2005 in Washington, DC, AAer this hearing, Respondent provided additional\ninformation for the record on May 12, 2005.\nFINDINGS F 4'IOLATION\nItem I in the Notice alleged that Respondent violated 49 C, F R. II 195. 452(b)(3) by failing to\ninclude provisions in its baseline assessment plan (BAP) to account for and address the\nsusceptibility of its pre-1970 low-frequency ERW piping to seam failures and the potential of its\npiping for stress corrosion crackmg (SCC) in the absence of sound technical Justificattons for\ndiscounting these risk factors. The integnty management program (IMP) regulations require\npipeline operators to identify and assess the risks associated with operating their pipehnes that. in\nthe event of a failure. could affect a high consequence area (HCA) In order to conduct a\nmeaningful risk analysis, a pipeline operator must accurately represent all of thc risks on a given\npipeline in its chosen risk model including assigning the appropriate weight to each risk factor\nrelative to other risk factors so that thc pipeline segments that pose the highest nsk to HCAs can\nbe appropnately priontized.\n\n\n\nWith respect to the ERW pipe issue, it has been commonly known throughout the pipeline\nindustry for many years that pipelines constructed before 1970 using low-frequency ERW\nlongitudinal seams and lap welded pipe are susceptible to scam failures. Based on htstoncal\npertormance, ERW and lap-welded pipe is susceptible to seam failure and presents a higher risk\nof failure than other pipe, all other factors being equal. Moreover, thc pipeline safety regulations\nexpressly deem all pre-1970 ERW pipe to be presumptively susceptible to seam failure.\nTherefore, the presence of pre-1970 ERW pipe is a significant risk factor and seam I'ailure is a\nfailure mode that operators of ERW pipe must fully address in their nsk analyses. In this case„\nseam failures on some of the actual ERW pipe in Respondent's Santa Fe Pacific Pipeline (SFPP)\nivere documented in OPS Techmcal Report 89-1\nIn its response and at the hearing, Respondent acknowledged that the susceptibility of pre-1970\nlow frequency ERW pipe to seam failures was known industry-wide as a significant rtsk.\nRespondent, however. contested the allegation that it failed to adequately address the presence ot\nERW pipe in its pipeline system in its IMP plan. In connection with the hearing. Respondent\nproduced a memorandum that purported to establish that it had replaced the ERW pipe it\nbelieved to be susceptible to seam failure. The memorandum noted that \"about a mile of the\nRichmond-Oakland 8-inch immediately downstream of Richmond Station and about 3. 5 miles of\nthe 10-mch San Diego Line through Tustin\" had been replaced. Notably, however, the study did\nnot document why only those small sections of ERW pipe were deemed to be high risk and the\nrest of the ERW ptpe in its system was not. Respondent also asserted that all of the remaining\nERW pipe in its SFPP was subJect to operating restrictions. OPS correctly pointed out. however.\nthat while the SFPP is a significant part of the Respondent's system it only represents about 25\npercent of the total mileage of Respondent's pipeline system to which its IMP applies. The\nassessment of pipelines that are susceptible to seam failures that could affect a HCA is a\nrequirement for all such pipelines. Respondent made no assertion that similar reviews had been\nconducted for its other pipel ines.\nOPS issued Alert Notices on January 28, 1988 and March 8, 1989 mforming pipelme operators that low-\nt'requency ERW pipe was sub)ect to longitudinal iield seam failures caused by the presence of manufactunng\ndefects in thc F RW seams that can grow over time Seam corrosion and cychc fatigue have been found to have\ncontributed to the growth of these defects and in some cases, operational failures have occurred many months or\nyears after successful hydrostatic testing was conducted. Thts is also retlected in subsequent rules For example. the\npreamble that accompamed publication of the rule estabtishmg a risk-based alternative to pressure testing, as\nfollows \"Pre-1970 electnc resistance welded (ERW) and lap welded pipelmes susceptible to longitudinal seam\nfailures exhibit the highest potential nsk because of their combination of probabihty of failure and potential for\nlarger volume releases as evidenced by histoncal records\" (63 FR 59475 Nov 4, 1998)\n49 C F R ti 195 303(d)\n\"FRW Summary for Liquid and Gas Transmission Lmes. \" (1989) At the time, this pipehne ivas known as the\nSouthern Pacilic Pipelme\nDunng thc 2003 inspection Respondent apparently did not present the SFPP study The memorandum provided\nby Respondent descnbmg the study made the followmg single qualitative generahzation 'a targe portion of the pipe\npurchased by SPPL in the mid to late 1960's was manufactured ai Kaiser's Fontana mill using modern techmques\nand is of good quality. \" (Letter from Engelhardt to DesBarres, Sept 8, 1989)\n\n\n\nRespondent also asserted that its subject matter experts (SMEs) had concluded that its pipe was\nnot susceptible to seam failure. At the time of the inspection, however, Respondent presented no\nseam analysis or other documentation demonstrating that a thorough engineering or metallurgical\nanalysis on the susceptibility of its ERW pipe to seam failures had been conducted. Moreover. at\nthe time of the inspection, Respondent's \"Bass Trigon\" computer risk model reflected\nRespondent's apparent lack of information about the type ot longitudinal seam for many\nsegments of its pipeline system. The data used for the seam type for a significant number of\npipeline segments in the risk model were listed as \"unknown\"\nRespondent also argued that there was a lack of industry guidance for how to perform an\nengineering analysis to determine the susceptibility of particular ERW pipe to seam failures.\nOPS, however, pointed out that guidance was available for performing ERW analysis. To take\nJust one example. Dr. John Kiefner published a methodology for conducting such an analysis in a\npaper presented on February 2-6, 2002 at the ASME Engineering Technology Conference on\nEnergy, entitled \"Dealing With Low-Frequency-Welded ERW Pipe and Flashwelded Pipe With\nRespect To HCA-Related Integrity Assessments. \" While pipeline operators are not required to\nfollow Dr. Ktefner's methodology, the availability of his methodology is sufficient to establish\nthat industry guidance for conducting an engineering analysis to determine the susceptibility of\nERW pipe to seam failure was available to Respondent in advance of the inspection. '\nRespondent further asserted that in-line electromagnetic acoustic transducer (EMAT) inspection\ntools capable of detecting seam defects were only just becoming commercially available at the\ntime of the inspection. This assertion, however, is not relevant to the merits of thc allegation.\nRespondent was cited tor failing to identify wluch of its lines are susceptible to seam failure and\nto schedule an assessment for those lines. Even if the EMAT technology was not available at the\ntime, other methods were available by which to conduct integrity assessments for seam defects\nincluding hydrostatic pressure test, ultrasonic in-line crack detection tools. and transverse flux\nmagnetic flux leakage in-line crack detection tools. Respondent was aware of other technologies\navailable for conducting assessments tor cracks and seam defects.\nFinally, we note that one of the key technical factors in determining susceptibility to seam failure\nts the degree of cyclic loading experienced by a given line. Pressure cycling promotes defect\ngrowth and can contribute to eventual failure. Respondent, like many other hazardous liquid\npipeline operators, performs batch operations on its mainlines and delivery lines which typically\ngenerates frequent pressure cycling. Absent a strong technical justification to the contrary, any\nERW line operated under these circumstances should be considered susceptible to seam failure.\nand assessment methods must be selected accordingly. In a system of approximately 10. 000\nmiles of pipelines, composed of numerous older legacy systems subject to frequent pressure\ncycling, Respondent's claim that it had no segments considered susceptible to seam failure was\nunpersuasive. Overall. Respondent failed to demonstrate that its decision to exclude the\nRespondent stated that it subsequently adopted an updated procedure based on the Baker study entitled ' Lotv\nFrequency ERW and Lap Welded Longitudinal Seam Evaluanon Final Report\" (Oct 2003), and Respondent\nemphasized that this report was issued after thc OPS mspection The Baker study however, wai conducted m\nassociation with Dr. Kiefner, and the suscepnbility analysis described m the Baker study is only a slightly updated\nversion of the analysis methodology Dr Kiefer presented to ASME in February 2002, as discussed aboie.\n\n\n\nsusceptibility of its ERW pipe to seam failures as a significant factor in its risk analysis was\njustified by sound technical analysis during the relevant time period.\nWith respect to stress corrosion cracking (SCC), Respondent acknowledged that SCC was a risk\non pipelines, but argued that because it had never expenenced a \"known\" SCC failure prior to\nthe inspection it was justifie in discounting SCC as a significant factor in its risk model OPS\npointed out that prior to the mid-1990s, Respondent had been to some degree mcffcctive in its\ndetermination of the causes of pipeline accidents to thc point that OPS had cited and levied a\ncivil penalty and compliance order against Respondent in 1994 — in part for its failure to\nascertain the causes of pipeline accidents. Therefore, it is possible that past accidents could have\nbeen caused by SCC, but were undiagnosed because there is reason to believe that Respondent\ndid not effectively determine the true cause of many historical accidents. In addition,\nRespondent built its extensive network of pipelines through acquisitions In order Ior\nRespondent to defend this assertion, it would have needed to present a rigorous review of the\nhistorical pipeline accidents on its legacy systems that occurred during previous ownership.\nTherefore, while Respondent may not have previously attributed a pipeline failure to SCC, this is\nnot the same thing as saying Respondent had no reason to consider SCC to be a potential risk\ntactor. Absent metallurgical reports on all past failures, Respondent's statement that its systems\nhave never experienced a SCC-related failure is inconclusive at best.\nRespondent also argued that it did not believe that the IMP rule contemplated the consideration\nof SCC as a threat to hazardous liquid pipelines at all. This argument, however. is unpersuasive.\nPublished guidance for implementation of the rule in Appendix C to 49 C. F. R. Part 195\nexplicitly lists SCC as a threat to be assessed with crack detection in-line inspection (II I) tools\nIn addition. the preamble to the IMP rule (65 FR 75396) specifically addresses crack detection\nand SCC in the BAP as follows:\nMrat Must Be in the Baseline Assessmerrt Plan? Section l95 452(c)\nCrack Detection: Since the early 1 990 's, pipeline operators liai'e successfirlly\nfield tested intenial inspection tools capable of nondestructii ely ideirtifying\nfatigue cracks and stress corrosioir crackrn in the longitudiiial seam. Researclr\narid dei'elopmeiit coiitiniies on these tools to strii e for reliable ide&iti ficatrorr of\notliei types of seanr defects, such as hook cracks IVitlr the use of ultrasonic and\nMFL (trans' erse orientation) technology, pipeline segments that hai e\ne~perrerrced fatigue cracking can now be iirspected. Cracks w itlr a potential to\nrupture can be ideiitified and repaired prior to groiiing to a critical stage. Tlris is\nparticrdarly important as this type of defect coiild suri ive iiritial and subsequerrt\npressure tests but their ~'ith pressure cychng, groN oi er time to a critical stage\nand leak or ruptiire (emphasis added j.\nThis put pipeline operators on notice that the intent of the rule language requiring operators to\ndevelop and tollow IMP plans was for BAPs to include assessments to address the nsks of crack\ndefects — including SCC because of its particular importance. Finally. Respondent cited OPS\nAdvisory Bulletin ADB 03-05 in an attempt to justify its assertion that the rule did not\n\n\n\ncontemplate consideration of the SCC threat. It is clear from the text of the IMP rule however,\nthat the rule did not specifically focus on any particular threat because it was intended that\noperators address all threats. Therefore, while Respondent correctly points out that this advisory\nbulletin was not issued until after the inspection, it merely notes that the rule did not specify\nSCC.\nRespondent also suggested that there was no techiucal guidance in place at the time of the\ninspection for industry or OPS inspectors to use in evaluating SCC threats. OPS, however,\npotnted out that numerous reference and research reports pertaining to SCC threats to pipelines\nhad been published by the time Respondent was developing its BAP. The Baker Report, for\nexample, compiled many references to SCC dating back to the 1970's. Some of the more\nimportant reports highlighted by Baker include:\n~ \"Report of the Inquiry [on] Stress Corrosion Cracking on Canadian Oil and Gas\nPipelines\" by the Canadian National Energy Board (NEB 1996).\n~ \"Stress Corrosion Cracking — Recommended Practices' published by the Canadian\nEnergy Pipeline Association (CEPA 1997a). Baker noted that \"[t]he document presents\nan excellent model for pipeline operators who are setting up procedures for preventing\ncontrolling and mitigating external SCC. \"\n~ CEPA produced an additional report that specifically addresses circumferential SCC.\na less common form of SCC (CEPA 1997b). Thts report documents the expenences of\nNOVA Gas Transmission Ltd.\n,\nNorthwestern Limited, Federated Pipe Lines Ltd. , and the\nSNAM system in Italy in investigating and mitigating leaks due to circumferential SCC.\nSubsequently, CEPA issued an addendum to the Stress Corrosion Cracking—\nRecommended Practices addressing circumferential SCC (CEPA 1998),\n~ \"Protocol to Prioritize Sites for High pH Stress-Corrosion Cracking on Gas\nPipelines\", Eiber and Leis (1998). In this report, Eiber and Leis document the\ndevelopment of a simple form for evaluating the susceptibility of a pipeline segment to\nhigh pH SCC An example of an SCC integrity management plan is also presented. This\ndocument provides good descriptions of the variables that are considered for determining\nthe degree of susceptibility of a pipeline to high pH SCC and presents summary level\nsupporting historical data.\nTherefore. Respondent's suggestion that there was no guidance available to industry by which to\nevaluate, assess, and manage thc threat ot SCC is unfounded.\nRespondent then argued that its IMP did address SCC because one paragraph in Section F3. 5\nreferenced SCC. Although Respondent's program description demonstrates that it was aware of\nthe factors that influence SCC risk as reflected in API-1160, compliance with the rule requires\nmore than a brief description of what should be done. The IMP rule requires that operators\nimplement and follow the program elements at each stage. Simply put, Respondent did not\n' Stress Corrosion Cracking Study with Database, i=tnal Report. \" Michael Baker Jr, Inc (Jan 2005) Whde the\nBaker report did not preceed the inspection. it did not document any new techtucal research. or develop any new\nguidance for handlmg SCC. Rather, the Baker report was a compendium and summary of existing research and\nguidance already available to industry assembled into one convenient source.\n\n\n\n6\nanalyze for SCC in prtoritiztng its segments for baseline assessments. To the contrary. it decided\nto turn off the following known risk factors for SCC in its computer risk model: age of pipe; type\nof coating; CP system conditions and levels; soil stresses; drainage type: degree of pressure\ncyclmg: excavation data; and fracture mechanics analysis.\nRespondent further asserted that its program was literally identical to API-1160. As a factual\nmatter this is incorrect. For example, the only basis offered by Respondent for turning off the\nSCC risk factor was a lack of known failures — but failure history is not listed in API-1160 as a\nconsideration when analyzing SCC risk attributes. API-1160 includes a number of guidance\nstatements on SCC including:\n~ AP 1-1160 indicates that SCC mspections should only be suspended or postponed after\ntwo consecutive assessments in which no new SCC sites were discovered (Section 9. 4, 2).\nThis guideline was not in Respondent's program (indeed they did not include any SCC\nassessments in their plan as of March 2003).\n~ API-1160 identifies continued hydrostatic testing to account for crack growth.\nincluding SCC specifically (Section 9. 5. 2). This guideline was not reflected in\nRespondent's program.\nAPI-1160 cautions that SCC may be present for many years before causing problems\n(Section A. 1. 6. 3). This is why past failure history alone is not a good enough indicator of\nSCC risk to be the sole reason for discounting it.\nNone of these guidelines were reflected in Respondent's BAP. Therel'ore, Respondent's written\nprogram was not identical to API-1160, much less implemented in accordance with the standard.\nIn fact. as noted above Respondent decided to turn off every risk factor in Respondent's Section\nF3. 5 that corresponded to API-1160 in its risk analysis computer model. Finally. it should be\nnoted that AP1-1160, Section 8. 4, \"Characteristics of a Sound Risk Assessment Approach\"\nexplicitly states that:\n\"rf risl- assessment shottld be investigative in nature, seehng to identify\npret iously unrecogni \"ed rhreats to pipeline integrity. It should mal e use of\npretiotts ei enis, bur focus on rite potential for fitture mishaps, inchiding sceiiarios\nthar may net er ltave liappened before. \"\nThe IMP rule requires pipeline operators to follow recognized industry practices in carrying out\ntheir IMP programs unless the operator can demonstrate that an alternative practice is supported\nby a rehable engineering evaluation. Respondent's approach reflected a reluctance to take an\ninvestigative approach to the identification of threats in order to avert pipeline accidents,\nincluding those caused by previously unrecognized threats to the pipeline.\nAccordingly, I tind that Respondent violated tl 195. 452(b)(3) by failing to include provisions in\nits BAP to account for and address the susceptibility of its pre-1970 low-frequency ERW piping\n49 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\nthe time the IMP rule was issued, it still serves as evidence of the generally accepted industry practice tor pipelme\nintegrity management programs\n\n\n\nto seam failures and the potential of its piping for SCC in the absence ot sound technical\ngustifications to discount these risk factors.\nItem 2a in the Notice alleged that Respondent violated 49 C. F. R. It 195. 452(e)(1)(i) by failing to\nconsider the results of previous integrity assessments including previously identified defect type\nand predicted growth rate in establishing an integrity assessment schedule prioritizing its pipeline\nsegments by risk Section 195. 452(e) requires a pipeline operator to base its assessment schedule\non all risk factors that reflect the risk conditions on each segment and list several such factors\nincludmg previous integrity assessments\nIn its response and at the hearing, Respondent acknowledged that it decided not to activate the\ncapability of its computer model to analyze previous mtegrity assessments, but contended that it\nused qualitative evaluation by its SMEs to evaluate those risk factors that it chose to turn off in\nthe computer model. After Respondent made this argument, OPS pointed out that Respondent s\nrisk ranking exactly matched the ranking produced by the computer model alone. OPS further\nnoted that because the omitted nsk factors were of such importance, it is implausible that any\nthorough SME analysis of these omitted factors would have zero influence on the resulting nsk\nranking. Moreover, the number of data elements listed in the matrices in Respondent's own\nexhibits that its SME s would have had to collect and analyze for a 10, 000 mile pipeline system\nwould have taken a significant period of time to conduct systematically and thoroughly and\nwould have generated large volumes of decision making information and technical analysis\ndocumentation that Respondent would have been required by regulation to maintain. \"\nRespondent did not present any such documentation. Therefore, even if Respondent's SMEs\ncontributed to the process to one extent or another, Respondent failed to demonstrate that the\nresultmg nsk analysis considered previous integrity assessments in a manner that permitted a\nmeanmgful risk rankrng. Accordingly, 1 find that Respondent violated ) 195. 452(e)(1)(i) by\nfailing to consider the results of previous integnty assessments including previously identified\ndefect type and predicted growth rate in establislung its integrity assessment schedule.\nItem 2b in the Notice alleged that Respondent violated 49 C. F. R. $ 195. 452(e)(1)(i») by failing\nto consider repair history in establishing an integrity assessment schedule prioritizing its pipeline\nsegments by risk. Respondent offered the same response to tlus item as for Item 2a above. For\nreasons already discussed, Respondent was unable to refute the allegation. Accordingly, I find\nthat Respondent violated g 195. 452(e)(1)(iii) by failing to consider repair history in establishing\nits integnty assessment schedule.\nItem 2c in the Notice alleged that Respondent violated 49 C. F. R. ( 195, 452(e)(1)(vii) by failing\nto consider local environmental factors, including soil corrosivity, subsidence, climactic\nconditions, and geo-technical hazards, in establishmg an integrity assessment schedule\nprioritizing its pipeline segments by risk. Respondent offered the same response to this item as\nt'or Item 2a above For reasons already discussed. Respondent was unable to refute the\nallegation. Accordingly, I find that Respondent violated $ 195. 452(c)( I )(vii) by failing to\nconsider local environmental factors including soil corrosivity, subsidence, climactic conditions.\nand geo-technical hazards in establishing its integrity assessment schedule.\n49 C. F R g 195 45'2(l)\n\n\n\nItem 2d in the Notice alleged that Respondent violated 49 C. F. R. $ 195 452(e)(1)(ix) by failing\nto consider physical support of a segment such as by a cable suspension bridge in establishing an\nintegrity assessment schedule prioritizing its pipeline segments by risk. Respondent offered the\nsame response to this item as for Item 2a above. For reasons already discussed, Respondent was\nunable to refute the allegation. For reasons already discussed. this argument was unpersuasive.\nAccordingly. 1 find that Respondent violated ) 195. 452(e)(1)(ix) by failing to consider physical\nsupport of a segment such as by a cable suspension bridge in establishing its integrity assessment\nschedule.\nItem 3a in the Notice alleged that Respondent violated 49 C. F. R. ) 195. 452(i)(2) by failing to\nmaintain documentation demonstrating that the risk model it used to identify the need for\npreventative and mitigative measures to protect the HCAs weighted and scored all of the relevant\nrisk factors in a manner permitting a meaningful risk analysis of its system. Respondent did not\ncontest this allegation. Accordingly, 1 find that Respondent violated ) 195. 452(i)(2), as more\nfully described in the Notice.\nItem 3b in the Notice alleged that Respondent violated 49 C. F. R. ) 195. 452(i)(2) by tailing to\ndemonstrate that weight assigned to product type by the risk model it used to identi1'y the need\ntor preventative and mitigative measures was justified given Respondent's actual operating\nexperience. Specifically, the Notice alleged that in some cases product type was weighted as\nmuch as 2:1 versus all other risk factors combined. OPS contended that because product type is\nmost strongly associated with internal corrosion risk. Respondent's decision to assign this level\nof weight to product type distorted its nsk analysis by overwhelming the risk weighting for other\nnsk factors actually identified as the cause ofhistorical failures on Respondent's system. such as\nfactors associated with external corrosion, third-party damage, or seam failures\nln its response and at the hearing, Respondent insisted that the weight it assigned to product type\nwas appropriate. OPS, however, showed that over the period from 1998 to 20Q3. while\nRespondent's pipelines experienced a number of failures, in no mstance was the primary cause\ndetermined to be internal corrosion. The integrity management regulations do not prescribe the\nweight to be assigned!o any single risk factor. A pipeline operator, however. is obligated to\nweigh all of the relevant risk factors in a manner permitting a meaningful risk analysis of its\nparticular system. Respondent failed to demonstrate that the weight it decided to assign to\nproduct type permitted a meaningful risk analysis given the historical causes of failures that\nactually occurred on its system. Accordingly, 1 find that Respondent violated $ 195. 452(i)(2) by\ntailing to demonstrate that the weight assigned to product type by the risk model it used to\nidentify thc need for preventative and mitigative measures was justified given Respondent's\nactual operating experience.\nItem 3c in the Notice alleged that Respondent violated 49 C. F. R ) 195. 452(i)(2) by failing to\ndemonstrate that the weights assigned to the HCA risk factors by the risk model it used to\nidentify the need for preventative and mitigative measures was based on the relative risk\nrelationships among those factors. Respondent did not contest this allegation, Accordingly. 1\nfind that Respondent violated ) 195. 452(i)(2), as more fully described in the Notice.\n\n\n\nItem 3d in the Notice alleged that Respondent violated 49 C. F. R. ( 195. 452(i)(2) by fail»g «\ndemonstrate that the weight assigned to segment length by the risk model it used to identify the\nneed for preventative and mitigative measures was justified given Respondent's actual operating\nexperience. Specifically, the Notice alleged that, with respect to the 212 ranked segments for the\nWestern/Midcon area. the average length of the 25 highest ranked segments was 1. 54 miles\nwhile the average length of the 25 lowest ranked segments was 54, 97 miles and that nothing in\nRespondent's operating history supported this scoring method.\nln its response and at the hearing, Respondent insisted that the weight it assigned to segment\nlenl~h was appropriate, OPS acknowledged that shorter lines can be in more populated areas,\nbut pointed out that longer lmes affect many HCAs where shorter lines affect few of them.\nMoreover, Respondent was unable to establish as a factual matter that its spill history supported\nits assertton that the shorter segments were at higher risk of failure. The integrity management\nregulations do not prescribe the weight to be assigned to any single risk factor, A pipel»c\noperator. however, is obligated to weigh all of the relevant risk factors in a manner permitting a\nmeaningful risk analysis of its particular system. Respondent failed to demonstrate that the\nweight it decided to assign to segment length permitted a meaningful risk analysis given the\nhistory of spills that actually occurred on its system. Accordingly, I find that Respondent\nviolated ) 195. 452(i)(2) by failing to demonstrate that the weight assigned to segment length by\nthe risk model it used to identify the need for preventative and mitigative measures was justified\ngiven Respondent's actual operating experience.\nItem 4 in the Notice alleged that Respondent violated 49 C. F. R. ) 195. 452(f)(3) by failing to\nintegrate available information concerning the age of in-line inspections and hydrostatic pressure\ntests into its integrity management analysis. In its response and at the hearing. Respondent\nacknowledged that its analysis did not differentiate prior assessments by age but argued that the\nintegrity management regulations were \"silent\" on whether differentiation of prior assessments\nby age was required. This argument, however, is unpersuasive. The integrity management\nregulations expressly require that operators consider the results of previous integrity assessments\nsuch as defect type and size, and defect growth rate. lt appears that for a system as large as\nRespondent's, OPS was willing to allow the age of previous assessments to serve as a kind ot\nproxy for the true conditions of each pipeline (based on the presumption that all previous\nassessments resulted in the identification and repair of all significant pipeline defects identified).\nPipelines recently assessed could therefore be presumed to be in relatively sound condition\nHowever, for older assessments, there is less assurance that the line remains in sound condition.\nScoring all hnes that had ever been assessed equally does not acknowledge the reality that lines\nthat have not been assessed in a long time are much more likely to have integrity-threatening\ndefects than lines which were assessed and repaired recently. Because Respondent only\nconsidered whether it had or had not conducted an assessment but failed to consider the results ot\nthe previous assessments, the actual condition of the line discovered during thc previous\nassessment was not captured. Respondent not only failed to analyze the results ot past\nassessments as required by the rule. but did not even use age differentiation to approximate this\nrequired risk factor in its analysis.\n\n\n\n10\nRespondent also suggested that no guidance on this issue was made available. However.\nAppendix C to 49 C. F. R. Part 195 speci tically guides the operator to consider \"Date of pig run\"\nin one of the hypothetical models. Moreover, as was noted previously the IMP rule directs\noperators to follow recognized industry practices in carrying out the integrity management\nrequirements. API 1160 Section 8. 8 stresses the importance of incorporating the results of\nprevious integrity assessments into the 'likelihood of failure\" estimation. Accordingly. I find\nthat Respondent violated P 195. 452(f)(3) by faihng to integrate available information concernmg\nthe age of previously conducted assessments into its integrity management analysis.\nItem 5 in the Notice alleged that Respondent violated 49 C. F. R. $ 195, 452(g) by failing to use\navailable pipeline data as inputs in its information analysis including basic information on seam\ndesign block valve rating, maximum expected discharge pressure, and internal corrosion\ninhibitor. At the hearing, Respondent acknowledged that the integrity management program\ndocumentation provided to OPS at the time of the inspection did not demonstrate that the\nspecified data sets were reflected in its integrity management program. Respondent did provide\nadditional data tabulation materials in connection with the hearing rellecting modifications that\nwere subsequently made to its program, but this material was for a different set of line segments\nand Respondent was unable to establish that this material represented the data tabulation\npractices Respondent had in place at the time of the inspection. ' Therefore. Respondent failed\nto demonstrate that it considered the results of previous integrity assessments in a manner\npermitting a meaningful risk analysis during the relevant time period. Accordingly, I tind that\nRespondent violated ( 195. 452(g) by failing to use available pipehne data as inputs in its\ninformation analysis.\nItem 6 in the Notice alleged that Respondent violated 49 C. F. R. ) 195. 452(e)(1)(iv) by failing to\ninclude eleven specified HCA line sections containing hazardous liquids in its BAP. Respondent\ndid not contest this allegation. Accordingly, I find that Respondent violated ) 195. 452(e)(1)(iv)\nas more fully described in the Notice.\nItem 7 in the Notice alleged that Respondent violated 49 C. F. R. ) 195. 452(d)(3)(ii) by failing to\nincorporate new HCAs or new information about existing HCAs into its BAP within one year\nfrom the date the areas were identified. Respondent did not contest this allegation. Accordingly.\nI find that Respondent violated tI 195. 452(d)(3)(ii) as more fully described in the Notice\nThese findings of violation will be considered prior offenses in any subsequent enforcement\naction taken against Respondent.\nSee footnote 7\n10 We make no determmation here as to tvhether these additional documents ~ere suNctent to iubiequentlp\nestabhsh compliance,\n\n\n\n11\nASSESS%1ENT OF PENALT\nUnder 49 U. S. C. g 60122, Respondent is subject to a civil penalty not to exceed $100, 000 per\nviolation for each day of the violation up to a maximum of $1, 000. 000 for a related series of\nviolations.\n49 U. S. C. 1) 60122 and 49 C. F. R, $ 190. 225 require that. in determining the amount ot the civil\npenalty. I consider the following criteria: nature, circumstances. and gravity of the violation.\ndegree of Respondent's culpability. history of Respondent's prior offenses, Respondent's ability\nto pay the penalty, good faith by Respondent m attempting to achieve compliance, the effect on\nRespondent s ability to continue in business, and such other matters as ]ustice may require.\nWith respect to Item I. the Notice proposed a civil penalty of $100, 000 for Respondent's failure\nto include provisions in its BAP to account for and address the susceptibility of its prc-1970 low-\nfrequency ERW piping to seam failures and the potential of its piping for SCC in the absence of\nsound technical justifications for discounting these risk factors. The safety of the public depends\non pipeline operators maintaining the integrity of their pipelines. Conducting an effective risk\nanalysis is a key step in order for pipeline operators to prioritize the integrity assessment of the\nhighest risk segments of their pipelines. If the risk analysis is not properly conducted at the\nbaselme assessment stage, it can adversely affect an operator's entire IMP program.\nIn its response and at the hearing, Respondent contended that the IMP rule only required that it\nhave a \"fratnework\" program and that the issues cited by OPS are merely improvements that it\nhad intended to develop over time. This argument, however, is unpersuasive. The IMP rule\nexpressly required that pipeline operators have the specified program elements in place by March\n31, 2002. \" Although continual evolution of IMP plans is certainly contemplated by thc IMP\nrule (indeed, operators are required to update their programs as new data is acquired). when\nrequired program elements such as prioritization of baseline assessments by risk were due to be\nimplemented. an operator's process for doing so must be mature, and nothing in the record\nwarrants concluding otherwise. In this case. all of the citations arose trom Respondent's\nomission of required program elements or lack of technical justification for program\nmethodologies,\nRespondent also questioned the adequacy of notice of how OPS intended to interpret and enforce\nthe IMP rule. The history of the IMP rule, however. demonstrates that OPS went to great lengths\nto provide operators with pre-enforcement guidance on how it would interpret and apply the\nrequirements of the IMP rule including holding public meetings, developing a extensive IMP\nwebsites. publishing detailed frequently asked questions (FAQs), and even publishing the\ninspection protocols later used by OPS in conductmg IMP compliance inspections. For example.\nOPS pointed out that the need to assess lines for the risk of cracks including SCC was\nemphasized during a 2002 Workshop attended bv Respondent s personnel in which crack tools\nwere specifically listed as assessment methods. ' Respondent has presented no information that\n49 C F. R t, 195 452(b)(1)\nSee 66 FR 35319 and 67 FR 31399 for more information on the IMP iiorkshopi\n\n\n\n12\nwould warrant a reduction in the civil penalty amount proposed in the Notice for this violation.\nAccordingly, having reviewed the record and considered the assessment criteria, I assess\nRespon","truncated":true,"body_characters":54549}