{"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":null,"summary":"CLOSED notice of probable violation citing 195.406(b), 195.410(a)(1), 195.420(c), 195.573(a)(1), 195.579(a).","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-420065023.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-420065023.md"},"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.\n\nOfficial case documents:\n\n420065023_Closure_07192012.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420065023/420065023_Closure_07192012.pdf\n\n420065023_Closure_07192012_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420065023/420065023_Closure_07192012_text.pdf\n\n420065023_FinalOrder_08312010.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420065023/420065023_FinalOrder_08312010.pdf\n\n420065023_FinalOrder_08312010_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420065023/420065023_FinalOrder_08312010_text.pdf\n\n420065023_FinalOrder_08312010_text.pdf\n\nAUG 31 10\nMr. Ronald G. McClain\nVice President, Operations and Engineering\nProducts Pipelines\nKinder Morgan Energy Partners, L.P.\n500 Dallas Street, Suite 1000\nHouston, TX 77002\nRe: CPF No. 4-2006-5023\nDear Mr. McClain:\nEnclosed please find the Final Order issued in the above-referenced case. It makes findings of\nviolation, assesses a civil penalty of $35,000, and specifies actions that need to be taken by\nKinder Morgan Energy Partners, L.P., to comply with the pipeline safety regulations. The\npenalty payment terms are set forth in the Final Order. When the civil penalty has been paid and\nthe terms of the compliance order completed, as determined by the Director, Southwest Region,\nthis enforcement action will be closed. Service of the Final Order by certified mail is deemed\neffective upon the date of mailing, or as otherwise provided under 49 C.F.R. § 190.5.\nThank you for your cooperation in this matter.\nSincerely,\nJeffrey D. Wiese\nAssociate Administrator\nfor Pipeline Safety\nEnclosure\ncc: Mr. Paul Biancardi, Counsel for Kinder Morgan Energy Partners, L.P.\n5818 Beaver Falls Drive\nKingwood, Texas 77345\nMr. R.M. Seeley, Director, Southwest Region, PHMSA\nCERTIFIED MAIL – RETURN RECEIPT REQUESTED [7009 1410 0000 2472 2797]\n\n\n\nU.S. DEPARTMENT OF TRANSPORTATION\nPIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION\nOFFICE OF PIPELINE SAFETY\nWASHINGTON, D.C. 20590\n____________________________________\nIn the Matter of )\nKinder Morgan Energy Partners, L.P., ) CPF No. 4-2006-5023\n)\n)\n)\nRespondent. )\n____________________________________)\nFINAL ORDER\nOn December 13-17, 2004, and August 1-5, 2005, pursuant to 49 U.S.C. § 60117, a\nrepresentative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office\nof Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of the facilities and\nrecords of Kinder Morgan Energy Partners, L.P. (Respondent or KM), in New Mexico, Texas,\nand Louisiana. In addition, from November 28 through December 16, 2005, pursuant to 49\nU.S.C. § 60117, a representative of the Arizona Corporation Commission, as agent for OPS,\nconducted an on-site pipeline safety inspection of Respondent’s facilities and records in Arizona.\nThe inspection covered facilities and records pertaining to a portion of Respondent’s Santa Fe\nPacific Pipeline (SFPP) and Cypress Pipeline (Cypress) systems.\nliquid hydrocarbon products and consists of approximately 372 miles of pipeline in New Mexico\nand Texas and 671 miles of pipeline in Arizona. Cypress transports Highly Volatile Liquids\n(HVLs), including ethane and propane, and consists of approximately 104 miles of pipeline in\nTexas and Louisiana.\n1 SFPP transports various\nAs a result of the inspection, the Director, Southwest Region, OPS (Director), issued to\nRespondent, by letter dated May 30, 2006, a Notice of Probable Violation, Proposed Civil\nPenalty, and Proposed Compliance Order (Notice). In accordance with 49 C.F.R.\n§ 190.207, the Notice proposed finding that Respondent had violated 49 C.F.R. §§ 195.406(b),\n195.410(a)(1), 195.573(a)(1), and 195.579(a), assessing a civil penalty of $35,000 for the alleged\nviolations, and ordering Respondent to take certain measures to correct the alleged violations.\nThe Notice also proposed finding that Respondent had committed certain probable violations of\n49 C.F.R. 195.420(c) and warning Respondent to take appropriate corrective action to address\nthem or be subject to future enforcement action.\n1 Both pipeline systems are owned by Kinder Morgan Energy Partners, L.P., and operated by its subsidiaries. The\nsubject portion of the SFPP pipeline system is operated by SFPP, L.P., and the Cypress Pipeline system is operated\nby Kinder Morgan Operating, L.P.\n\n\n\n2\nKM responded to the Notice by letter dated June 30, 2006 (Response). The company contested\nall the allegations and requested a hearing. At Respondent’s request, the materials in the OPS\ncase file, including the OPS Violation Report, were provided to Respondent on January 24, 2007.\nA hearing was held on February 9, 2007, in Houston, Texas, with an attorney from the Office of\nChief Counsel, PHMSA, presiding. Respondent provided numerous documents at the hearing\n(Hearing Exhibits), which have been incorporated into the record for this case. Respondent was\nrepresented by counsel in this matter. Respondent arranged for an unofficial transcript of the\nhearing and provided copies to PHMSA on March 26, 2007.2 After the hearing, KM provided\nadditional information on March 26, 2007 (Closing).\nFINDINGS OF VIOLATION\nThe Notice alleged that Respondent violated 49 C.F.R. Part 195, as follows:\nItem 1: The Notice alleged that Respondent violated 49 C.F.R. § 195.406(b), which states:\n§ 195.406 Maximum operating pressure.\n(a) …\n(b) No operator may permit the pressure in a pipeline during surges or\nother variations from normal operations to exceed 110 percent of the\noperating pressure limit established under paragraph (a) of this section.\nEach operator must provide adequate controls and protective equipment to\ncontrol the pressure within this limit.\nThe Notice alleged that KM violated 49 C.F.R. § 195.406(b) by failing to provide adequate\ncontrols and protective equipment to control the pressure on its SFPP and Cypress pipelines\nwithin the limits established under § 195.406(a). Specifically, it alleged that neither system used\nfull-flow pressure relief valves and breakout tanks to relieve surges. At the hearing, OPS\npresented evidence that its inspectors observed that KM’s pipelines did not have such pressure\ncontrol devices, which led them to seek other evidence to indicate whether the lines had adequate\ncontrols and protective equipment. KM contested this allegation on both factual and legal\ngrounds.\nFirst, KM characterized Item 1 as an alleged failure to provide documentation of compliance\nwith § 195.406(b).3\nRespondent argued that § 195.406(b) contains no documentation\nrequirement and that therefore OPS’ allegation was based on a new interpretation of the\nregulation, of which KM did not have fair notice. I reject KM’s characterization of the allegation\nand its fair notice argument. During the inspection, OPS observed that Respondent’s systems did\nnot have full-flow pressure relief valves or breakout tanks. These devices are commonly used to\n2 I consider the transcript to be unofficial. PHMSA noted that the transcript contains numerous errors and\nmisattributions, but because of the informal nature of this matter, errors were not corrected before the transcript was\nfinalized and made part of the record.\n3 Response at 2.\n\n\n\n3\nrelieve pressure on pipelines during surges or other types of overpressure situations. The\nabsence of these devices led OPS to question whether Respondent had the adequate controls and\nprotective equipment required by the regulation. The Notice simply noted that KM could not\nproduce any documentation that it had taken steps to protect its systems from overpressure or\nthat it had actually considered the need for surge prevention. Nothing in the record indicates that\nOPS attempted to impose any sort of new documentation requirement or to cite KM for a failure\nto maintain records under § 195.406(b).\nSecond, KM argued that OPS, at the hearing, appeared to base the allegation of violation on a\nstatutory provision found in 49 U.S.C. § 60117(b) of the Pipeline Safety Laws. KM argued that\nno statutory violation could be found since none had been alleged in the Notice. Section\n60117(b) requires pipeline owners or operators to “(1) maintain records, make reports, and\nprovide information the Secretary requires; and (2) make the records, reports, and information\navailable when the Secretary requests.\nrequire pipeline owners or operators to provide documentation of compliance, OPS made clear in\nthe Notice and at the hearing that the basis of its allegation was KM’s failure to provide adequate\ncontrols and protective equipment, as required by § 195.406(b).\n”4 Although § 60117(b) gives PHMSA broad authority to\nThird, Respondent provided several documents in support of the argument that it had considered\nsurge overpressure and had provided adequate controls and protective equipment on its\npipelines.5\nSpecifically, Respondent provided pump station discharge and emergency and abnormal\noperation records. KM argued that these records supported its contention that pipeline pressures\nhad never exceeded the 110% Maximum Operating Pressure (MOP) limit set by the regulation\nand that OPS had failed to show that the company had ever exceeded the 110% limit.\nhowever, did not allege that Respondent had exceeded such MOP on the subject pipelines but,\nrather, that KM had failed to provide adequate controls and protective equipment to prevent the\npressure from exceeding 110% of MOP. Furthermore, Respondent’s operating history does not\nconfirm the adequacy of controls and protective equipment, nor does it indicate that surge\noverpressure had been adequately analyzed. A lack of historical overpressure events on these\nsystems may have been more a matter of luck than compliance with the regulation.\n6 OPS,\nKM also provided various MOP studies that had been conducted of the SFPP and Cypress\npipelines, but these too fail to establish that the company had provided adequate controls and\nprotective equipment to control pressure within the prescribed limits.\n7\nThe SFPP studies only\n4 49 U.S.C. § 60117(b). The authorities vested in the Secretary of Transportation by § 60117 have been delegated to\nPHMSA by 49 C.F.R. § 1.53.\n5 Response at 2.\n6 Id.\n7 Hearing Exhibit 1A, SPEC SERVICES, PRELIMINARY WESTERN PIPELINES MAXIMUM OPERATING PRESSURE STUDY,\nL.S. 17-19/21/22 EL PASO– TUCSON (23 Dec. 2003); Hearing Exhibit 1B, SPEC SERVICES, PRELIMINARY WESTERN\nPIPELINES MAXIMUM OPERATING PRESSURE STUDY, L.S. 4/5/6/86 EL PASO – TUCSON (23 Dec. 2003); Hearing\n\n\n\n4\nconsidered a narrow range of scenarios and did not account for others that could lead to\noverpressure events. For example, the studies did not account for the possibility of a pressure\nwave rebound off a suddenly closed valve after an abnormal station shut-down. Nor did the\nstudies consider the possibility of valve closures other than for station valves. The studies even\nacknowledged the possibility that overpressure events could occur. Finally, KM made\nsignificant modifications to the SFPP system after the completion of the studies in 2003. Such\nmodifications could have changed what overpressure equipment and controls were necessary to\nprotect SFPP, yet there is no evidence in the record that the effects of such modifications on the\nrisk of overpressure were ever considered. Without considering such modifications, Respondent\ncould not accurately determine whether its controls and protective equipment were adequate.\nAs for KM’s Cypress study, it was completed in 2007, long after the inspection had been\nconducted and the Notice issued in this proceeding.\nsurge overpressure scenario involving the closure of a delivery valve. Other potential surge\noverpressure scenarios were not considered at all. Therefore, I find that the 2007 study is not\nprobative of whether Respondent provided adequate controls and protective equipment on the\nCypress line as of the dates of the 2004-05 inspections.\n8 In addition, the study evaluated a single\nFinally, KM argued that an engineer for Enron, the previous operator of the Cypress Pipeline,\nhad informed Respondent that a surge study had been performed on that line prior to KM’s\nacquisition. Respondent stated that this engineer had represented that “surge was not an issue for\nIn the absence of evidence beyond an undated, undocumented verbal statement, I cannot\nthis HVL pipeline.”9 KM provided no documentation of this study or basis for such a statement.\nconclude that KM provided adequate controls and protective equipment on the Cypress Pipeline.\nInherent in the requirement that KM provide “adequate” controls and protective equipment is the\ncompany’s obligation to use reasonable means to determine what is “adequate” for its own\npipeline systems and to document such a decision-making process. If Respondent has not\nperformed such an analysis, it might, for example, select undersized protective equipment or an\ninsufficient number of pressure control devices. Without such an analysis, neither Respondent\nnor PHMSA can determine whether it has simply been a matter of luck that an overpressure\nsituation has not occurred.\nAccordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.\n§ 195.406(b) by failing to provide adequate controls and protective equipment to control the\npressure on its SFPP and Cypress systems within the limits established according to\n§ 195.406(a).\nExhibit 1C, ANALYSIS OF RECOMMENDATIONS, PRELIMINARY 2003 SURGE REPORTS FOR 8\" AND 12\" EI PASO TO\nTUCSON PIPELINE.\n8 Hearing Exhibit 1D, LINDEN PROFESSIONAL SERVICES, CYPRESS PIPELINE SYSTEM HYDRAULIC and SURGE ANALYSIS\n(1 Feb. 2007).\n9 Response at 2.\n\n\n\n5\nItem 2: The Notice alleged that Respondent violated 49 C.F.R. § 195.410(a)(1), which states:\n§ 195.410 Line markers.\n(a) Except as provided in paragraph (b) of this section, each operator\nshall place and maintain line markers over each buried pipeline in\naccordance with the following:\n(1) Markers must be located at each public road crossing, at each\nrailroad crossing, and in sufficient number along the remainder of each\nburied line so that its location is accurately known.\nThe Notice alleged that KM violated 49 C.F.R. § 195.410(a)(1) by failing to place and maintain\nline markers over its SFPP Pipeline in sufficient number so that the line’s location was\naccurately known. Specifically, it alleged that when crossing cultivated agricultural fields, the\nmarkers on the far side of the field often could not be seen. The Notice also alleged that the\nlocation of the pipeline could not be discerned in some locations because of tall brush on the\nright-of-way.\nKM objected to the so-called “line-of-sight” test used by OPS to determine the adequacy of\nRespondent’s pipeline marking in cultivated fields and argued that it did not have fair notice that\nthe regulation required such a test. PHMSA acknowledges that while many operators follow the\nso-called “line-of-sight” test, as applied in the Notice in this case, many others do not.\nFurthermore, the regulation does not expressly require “line-of-sight.” In an effort to arrive at\ngreater consensus on this and other line-marking issues, PHMSA convened a public workshop in\nsuch circumstances, I find it appropriate to withdraw this portion of the allegation of violation.\nSuch withdrawal neither constitutes an interpretation of § 195.410(a)(1) nor prejudices future\npotential enforcement action against Respondent or any other operator. Having withdrawn this\nportion of the allegation, I do not reach Respondent’s fair notice argument on the “line-of-sight”\ntest.\n2008 and is currently considering whether to issue a notice of proposed rulemaking.10 Under\nKM did not contest the allegation that in some areas the location of the pipeline could not be\ndiscerned because of tall brush in the right-of-way.11 KM indicated that it would “review the\n[right-of-way] for tall brush impeding the view of the line markers and eliminate the same.”12\nAccordingly, based on the foregoing, I find that Respondent violated 49 C.F.R. § 195.410(a) by\nfailing to maintain line markers over the SFPP pipeline so that its location was accurately known.\nItem 4: The Notice alleged that Respondent violated 49 C.F.R. § 195.573(a)(1), which states:\n10 PHMSA held a public workshop on February 20-21, 2008, in Houston, Texas, to discuss, among other issues, the\nplacement of line markers. Pipeline Safety: Workshop on Public Awareness Programs for Pipeline Operators and\nLocation of Line Markers, 73 Fed. Reg. 223 (Jan. 2, 2008).\n11 Response at 3.\n12 Id.\n\n\n\n6\n§ 195.573 What must I do to monitor external corrosion control?\n(a) Protected pipelines. You must do the following to determine\nwhether cathodic protection required by [Subpart H] complies with\n§ 195.571:\n(1) Conduct tests on the protected pipeline at least once each calendar\nyear, but with intervals not exceeding 15 months. However, if tests at\nthose intervals are impractical for separately protected short sections of\nbare or ineffectively coated pipelines, testing may be done at least once\nevery 3 calendar years, but with intervals not to exceed 39 months.\nThe Notice alleged that KM violated 49 C.F.R. § 195.573(a) by failing to properly conduct tests\non its cathodically protected pipelines. Specifically, it alleged that KM failed to consider IR\ndrop13 during the Company’s annual corrosion surveys on the SFPP and Cypress pipeline\nsystems.\nThe primary purpose of the annual testing required by § 195.573(a)(1) is to provide an operator\nwith sufficient information about its cathodic protection system to determine whether it is\nmeeting the requirements of § 195.571. Such information allows an operator to take action to\nremedy any inadequate cathodic protection and to comply with one or more of the applicable\ncriteria and other considerations contained in paragraphs 6.2 and 6.3 of NACE Standard\nRP0169-2002 (NACE Standard).\n14\nCathodic protection can limit external corrosion on buried pipelines through the application of\ndirect electric current to the metal of the pipeline. Protection is achieved when current flows to\nthe metal in an amount sufficient to prevent the loss of metal from the pipeline to the\nsurrounding environment. If insufficient current is provided, corrosion can result. The NACE\nStandard provides reference criteria against which Respondent can measure the flow of electric\ncurrent to or from its pipelines (pipe-to-soil potential).\nIn order to obtain an accurate reading of pipe-to-soil potential, Respondent must consider IR\ndrop when it conducts annual tests of its cathodic protection system. If IR drop is not\nconsidered, cathodic protection may appear to meet the criteria required by § 195.571, when, in\nfact, it does not. Therefore, when IR drop is not considered, such surveys do not achieve their\nintended purpose and therefore do not comply with § 195.573(a).\nParagraph 6.2 of the NACE Standard sets out four methods for considering IR drop (Methods),\nand provides, in relevant part:\n13 IR drop is an error in the pipe-to-soil voltage measurement caused by the electrical resistance of the soil in which\nthe pipeline is buried.\n14 NACE INTERNATIONAL, NACE STANDARD RP0169-2002 CONTROL OF EXTERNAL CORROSION ON UNDERGROUND\nOR SUBMERGED METALLIC PIPING SYSTEMS. This standard is incorporated by reference into the pipeline safety\nregulations; see 49 C.F.R. § 195.3.\n\n\n\n7\nNote: Consideration is understood to mean the application of sound\nengineering practice in determining the significance of [IR] drops by\nmethods such as:\n6.2.2.1.1.1 Measuring or calculating the [IR] drop(s);\n6.2.2.1.1.2 Reviewing the historical performance of the cathodic\nprotection system;\n6.2.2.1.1.3 Evaluating the physical and electrical characteristics\nof the pipe and its environment; and\n6.2.2.1.1.4 Determining whether or not there is physical evidence\nof corrosion.\nSFPP System\nRespondent uses an impressed current cathodic protection system on the SFPP system. During\nthe hearing, OPS argued that KM’s 2004 annual cathodic protection survey data revealed that the\ncompany was not accounting for IR drop at the test locations where it used the 850 mV NACE\ncriteria. OPS contended that Respondent was taking IR drop readings from certain testing\nlocations and extrapolating the readings to other locations, rather than measuring the actual IR\ndrop at each one. According to OPS testimony, the IR drop could be different among various\ntest locations due to differences in soil and environmental conditions. OPS asserted that when\nKM extrapolated IR drop to other testing locations, rather than considering the actual IR drop at\neach one, it may not have had an accurate indication of IR drop.\nRespondent acknowledged that it was extrapolating IR drop measurements when performing\ncathodic protection testing, but argued that its historical experience from hundreds of test\nlocations with similar conditions was consistent with “sound engineering practices” and\ntherefore in compliance with the regulation. In support of its argument, Respondent cited a 1991\nindustry training guide on cathodic protection that stated: “Although it is beneficial to remove IR\ndrop from all potential readings, it is not necessary to measure IR drop at each location each time\na potential reading is made. IR drop measurements made at one location may be applied to other\nnot establish compliance with either the regulation or the NACE criteria incorporated therein.\nsimilar locations.”15 The statements in the FERA Corporation’s training document, however, do\nI find that Respondent’s practice of extrapolating IR drop measurements from certain test\nlocations to others is not consistent with the NACE Standard and therefore does not satisfy the\nannual testing requirement set out in § 195.573. Respondent measured IR drop, a permissible\nMethod under the NACE Standard, but only at some locations. From location to location and\nyear to year, environmental and soil conditions can change, resulting in changed soil resistivity\nand, consequently, different IR drops. Respondent’s practice of extrapolating IR drop data\nacross its system does not account for the potential for environmental and soil changes at each\n15 Hearing Exhibit 4E, FERA CORPORATION, IR DROP, 4 (1991).\n\n\n\n8\ntest location. This practice does not satisfy the NACE Standard because it could leave\nRespondent with an inaccurate understanding of IR drop on its system.\nParagraph 6.3 of the NACE criteria specifically recognizes the potential for different soil and\nenvironmental conditions at different locations when it provides that “once determined, the\nvoltage drop(s) may be used for correcting future measurements at the same location, providing\nconditions such as pipe and cathodic protection system operating conditions, soil characteristics,\nmay, in certain circumstances, use the voltage drop at a particular location to analyze and\nconsider future readings at the same location, but not at others.\nand external coating quality remain similar” (emphasis added).16 In other words, an operator\nFinally, Respondent argued that the leak history of the SFPP system demonstrated the adequacy\nof its cathodic protection system. I disagree. As noted above, an absence of leaks may simply\nbe a matter of luck rather than evidence of compliance with the regulation.\nCypress System\nRespondent uses galvanic anode groundbeds to provide cathodic protection on the Cypress\nsystem. Respondent’s galvanic anodes are connected directly to the pipeline. In this design, the\nanodes corrode, or self-sacrifice, in order to protect the pipeline from corrosion. These\nsacrificial anodes must be periodically replaced when they become corroded to the extent they no\nlonger provide protection. Unlike an impressed current system, no external power source is\nused. While the Cypress system has a different design than the SFPP system, the cathodic\nprotection principles are generally the same.\nThe Notice alleged that Respondent did not account for IR drop in its annual cathodic protection\nsurveys of the Cypress system. In its Response, during the hearing, and in its Closing,\nRespondent argued that it had considered IR drop on the Cypress system through “sound\nengineering practice,” as permitted by NACE Standard paragraph 6.2.2.1.1.17 KM asserted that\nalthough it did not measure or calculate IR drops on the Cypress pipeline directly, it employed a\ncombination of the three other Methods for “consideration” of IR drop,\n18 as permitted by NACE\nStandard paragraph 6.2.\n19\nFirst, Respondent argued that it used 2004 in-line inspection (ILI) data to show that there were\nvery few external corrosion anomalies on the Cypress Pipeline.20\nRespondent also argued that\n16 NACE STANDARD, 6.3.1.\n17 Closing at 11.\n18 Response at 5-6; Closing at 10-11.\n19 Id. Respondent stated that OPS had a “grievance with RP 169 for permitting the use of ‘sound engineering\npractices,’” and wished to “substitute its engineering judgment for that of the operator.” Closing at 11. On the\ncontrary, it appears that OPS did not have an issue with the use of sound engineering practices, but instead with how\nRespondent demonstrates that its practices are sound.\n20 Response at 5; Hearing Exhibit 4H.\n\n\n\n9\nthe ILI data served as an evaluation of the physical condition of the pipe and revealed that the\ncathodic protection system was performing well.\n21 OPS countered, however, that ILI is just a\nsnapshot in time of the corrosion profile of the pipeline. OPS also pointed out that the NACE\nStandard cautions operators that ILI may not detect certain kinds of corrosion.\nRespondent may use ILI as part of a larger program for determining the adequacy of corrosion\ncontrol, ILI alone does not show that an operator is adequately considering IR drop.\n22 While\nSecond, Respondent argued that historical data from exposed pipe reports showed little evidence\nof corrosion or disbonded coating.23 Respondent asserted that these reports showed that Cypress\nwas receiving adequate cathodic protection and that Respondent was indeed considering IR\ndrop.\nEvidence that the pipeline, at one time, was free of corrosion or coating damage at these specific\nlocations does not, alone, show that cathodic protection is currently adequate along the entire line\nor that IR drop has been properly considered. Moreover, Respondent did not provide the\nexposed pipe reports or any explanation of how it analyzed the report contents to conclude that\nIR drop was fully considered. In the absence of such documentation and analyses, I reject\nRespondent’s argument.\n24 Pipe reports only offer a snapshot of select locations along this 104-mile pipeline.\nThird, Respondent indicated that it considered soil resistivity to evaluate the electrical\ncharacteristics of the pipe and environment.25 Respondent asserted that soil resistivity data from\nexposed pipe reports and Respondent’s “knowledge of the right-of-way conditions indicate low\nsoil resistivity along the Cypress pipeline right-of-way.”26 Respondent concluded that its\nevidence or analysis of how it concluded that soil resistivity was low. In the absence of such\nevidence and analysis, OPS cannot assess what sort of data was collected or from what\nlocation(s), whether the data was representative of resistivity elsewhere on the pipeline, and what\nvalue it had in considering IR drop.\n“knowledge” supported “a generally negligible IR.”27 However, Respondent provided no\n21 Response at 5-6; Hearing Exhibit 4H.\n22 See NACE STANDARD paragraph 6.3.3, “Absence of external corrosion damage or the halting of its growth may\nindicate adequate external corrosion control. The [ILI] technique, however, may not be capable of detecting all\ntypes of external corrosion damage, has limitations in its accuracy, and may report as anomalies items that are not\nexternal corrosion. For example, longitudinal seam corrosion and general corrosion may not be readily detected by\nin-line inspection. . . . The appropriate use of in-line inspection must be carefully considered.”\n23 Response at 5. While Kinder Morgan’s Response indicated that the exposed pipe reports have indicated no\ncorrosion and well-bonded coating, during the hearing Respondent indicated that 170 of 175 reports from 1991\nthrough 2006 gave no indication of corrosion or coating damage. Presumably, the remaining five reports did\nprovide some indication of corrosion or coating damage.\n24 Id.\n25 Id.\n26 Id. at 6.\n27 Id.\n\n\n\n10\nFourth, Respondent indicated that it had reviewed the historical performance of its cathodic\nprotection system by reviewing pipe-to-soil potential readings from annual corrosion surveys.\nRespondent indicated that this action, in combination with other considerations, showed that the\ncompany had considered IR drop. Here, again, Kinder Morgan failed to explain or provide\ndocumentation as to how its review of historical data showed that IR drop had been properly\nconsidered. The survey data provided by Respondent showed only the measured pipe-to-soil\npotentials, not whether or how IR drop had been measured.28\nFinally, Respondent asserted that a lack of corrosion-related leaks on the Cypress system showed\nthat corrosion was being adequately addressed.\nSFPP Pipeline, an absence of corrosion-related leaks may simply be more a matter of luck than\nevidence of compliance with the regulation.\n29 I disagree. As noted above in relation to the\nIn summary, while Respondent has taken some steps to consider IR drop, it has not satisfied the\nNACE Standard or the regulation because its application of the Methods for considering IR drop\nonly focused on certain locations along the pipeline. This practice does not account for\ndifferences in environmental and soil conditions, and the resulting differences in IR drop, that\ncould occur throughout the SFPP and Cypress systems. In addition, Respondent has not\nprovided evidence to support its arguments on exposed pipe reports or its knowledge of soil\nresistivity.\nAccordingly, based on the foregoing, I find that KM violated 49 C.F.R. § 195.573(a) by failing\nto properly conduct tests on its cathodically protected SFPP and Cypress Pipeline systems.\nItem 5: The Notice alleged that Respondent violated 49 C.F.R. § 195.579(a), which states:\n§ 195.579 What must I do to mitigate internal corrosion?\n(a) General. If you transport any hazardous liquid or carbon dioxide\nthat would corrode the pipeline, you must investigate the corrosive effect of\nthe hazardous liquid or carbon dioxide on the pipeline and take adequate\nsteps to mitigate internal corrosion.\nThe Notice alleged that KM violated 49 C.F.R. § 195.579(a) by failing to investigate the\ncorrosive effects of the hazardous liquid on its SFPP and Cypress systems.\nRespondent denied the allegation, arguing that its past efforts satisfied the requirement that it\ninvestigate the corrosive effect of hazardous liquid on its pipelines. KM contended that it had\ntested its SFPP system in the early 1990s for internal corrosion, using Electric Resistance (ER)\nprobes.30\nAccording to the company, such testing showed that corrosion rates were lower than\none mil per year on all ER probes, and that such data supported its decision to cease the use of all\n28 See Hearing Exhibit 4G.\n29 Response at 6.\n30 Id.\n\n\n\n11\nER probes in 1994.31 KM also argued that ILI runs had “supported a lack of internal corrosion”\nin the SFPP system.32 Regarding the Cypress Pipeline, KM argued that its specifications for the\nline prohibited any free water from entering the system.\n33 KM also argued that a 2004 ILI of the\nCypress line revealed no indications of internal corrosion and that a coupon installed from 1994\nto 1997 showed minimal corrosion rates.34 Respondent argued, therefore, that it did not\ntransport hazardous liquid that would corrode the Cypress Pipeline.35\nI find Respondent’s argument unpersuasive. The current version of Part 195 of title 49, Code of\nFederal Regulations, was established pursuant to the Hazardous Liquid Pipeline Safety Act of\n1979 (Pub. L. 96-129)(Act). The purpose of the Act and the regulations promulgated thereunder\nis to provide adequate protection against risks to life, property, and the environment posed by the\ntransportation of hazardous liquids. The regulations cover the design, construction, operation,\nmaintenance, and emergency response requirements for hazardous liquid pipeline facilities. A\nmajor goal of the regulations is to ensure that pipeline operators prevent and control corrosion in\ntheir pipeline systems, one of the major causes of pipeline failures. Operators transporting\nhazardous liquid are obligated to recognize and address corrosion and to prevent corrosion-\nrelated leaks and failures on their pipelines.\nThe phrase “hazardous liquid . . . that would corrode the pipeline,” as used in § 195.579(a), must\nbe construed in a manner that gives effect to the purpose and intent of the Act and the Part 195\nregulations. The intent of this section is to prevent harmful leaks of hazardous liquid caused by\ninternal corrosion. To accomplish this objective, pipeline operators are required to monitor their\npipelines wherever internal corrosion could be present and to take appropriate actions to\nminimize the corrosion in a manner that prevents leaks and other hazards. Known causes of\ninternal corrosion include certain materials commonly found in hazardous liquid pipeline\nsystems, including carbon dioxide, hydrogen sulfide, water, sediments, and microbes that can\ncause or contribute to internal corrosion. Other factors may also serve to amplify the corrosive\neffects of these materials, including low spots and locations where the hazardous liquid does not\nhave sufficient velocity to carry away water and sediments.\nIn this case, Respondent’s limited use of coupons and ER probes in the past demonstrated that\nthere was corrosion occurring on both the SFPP and Cypress systems, though apparently at a low\nrate. Any number of changes or upsets in upstream processes, however, could introduce\ncorrosive materials into the hazardous liquid, despite KM’s routine procedures or any\nspecifications prohibiting the presence of water in the lines. Therefore, I find that KM transports\na hazardous liquid that would corrode the pipeline.\n31 Id.\n32 Id.\n33 Id.\n34 Id.\n35 Id.\n\n\n\n12\nFurthermore, even though corrosion rates on these two systems may have been low in the past,\nthis does not mean that KM may cease investigating the corrosive effects of the hazardous\nliquids being transported. To account for potential changes or upsets, KM must investigate the\ncorrosive effects of the hazardous liquids transported in its pipelines on a continuing basis.\nRespondent’s practice of ILI may be useful in detecting corrosion, but ILI alone is inadequate to\nsatisfy the regulation. ILI only gives a snapshot in time of the condition of the pipe. Corrosion\ncan occur in the years between ILI runs if water or other corrosive materials accumulate inside\nthe system. In addition, ILI of mainline pipe does not provide information on an entire pipeline\nsystem because internal corrosion generally occurs first in dead- and intermittent-flow areas that\ncannot typically accommodate ILI tools. In light of the possibility that water or other corrosive\nmaterials may enter the pipeline systems at any time, I reject KM’s arguments that its past efforts\nsatisfied the requirements of the regulation.\nAccordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.\n§ 195.579(a) by failing to investigate the corrosive effects of the hazardous liquid on its pipeline.\nThese findings of violation will be considered prior offenses in any subsequent enforcement\naction taken against Respondent.\nASSESSMENT OF PENALTY\nUnder 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed\n$100,000 per violation for each day of the violation, up to a maximum of $1,000,000 for any\nrelated series of violations. In determining the amount of a civil penalty under 49 U.S.C.\n§ 60122 and 49 C.F.R. § 190.225, I must consider the following criteria: the nature,\ncircumstances, and gravity of the violation, including adverse impact on the environment; the\ndegree of Respondent’s culpability; the history of Respondent’s prior offenses; Respondent’s\nability to pay the penalty and any effect that the penalty may have on its ability to continue doing\nbusiness; and the good faith of Respondent in attempting to comply with the pipeline safety\nregulations. In addition, I may consider the economic benefit gained from the violation without\nany reduction because of subsequent damages, and such other matters as justice may require.\nThe Notice proposed a total civil penalty of $35,000 for the violations cited above.\nItem 1: The Notice proposed a civil penalty of $10,000 for Respondent’s violation of 49 C.F.R.\n§ 195.406(b), for failing to have adequate controls and protective equipment to control the\npressure on its SFPP and Cypress Pipeline systems within the limits established under\n§ 195.406(a). Adequate pressure controls and protective equipment are important to pipeline\nsafety because they serve to prevent pipeline overpressure and possible ruptures, spills, and harm\nto life, property, and the environment. KM’s violation reduced the margin of safety provided by\nthe regulation.\nGiven the potential threat posed by inadequate pressure controls, I find that the gravity of the\nviolation supports the proposed penalty amount. In addition, the violation continued for a\nsubstantial period yet the proposed penalty is far below the $100,000 per violation per day limit.\nThis amount reflects the fact that no pipeline failures or spills were associated with the violation.\n\n\n\n13\nKM has not presented any other evidence or argument justifying a reduction or elimination of the\nproposed penalty. Accordingly, having reviewed the record and considered the assessment\ncriteria, I assess Respondent a civil penalty of $10,000 for violation of 49 C.F.R. § 195.406(b).\nItem 4: The Notice proposed a civil penalty of $25,000 for Respondent’s violation of 49 C.F.R.\n§ 195.573(a), for failing to properly conduct annual tests on its cathodically protected SFPP and\nCypress Pipeline systems. As noted above, I found that KM failed to properly consider IR drop\nwhen performing annual tests of its cathodic protection system. As a result, Respondent may not\nhave had an accurate understanding of the effectiveness of its cathodic protection system.\nInadequate cathodic protection may lead to external corrosion, which, in turn, can result in\npipeline leaks or failures. This violation continued for many days, which serves to increase the\ngravity of the offense and the amount of the proposed penalty. In addition, the violation\ncontinued for a substantial period yet the proposed penalty is far below the $100,000 per\nviolation per day limit. KM has not presented any other evidence or argument justifying a\nreduction or elimination of the proposed penalty. Accordingly, having reviewed the record and\nconsidered the assessment criteria, I assess Respondent a civil penalty of $25,000 for violation of\n49 C.F.R. § 195.573(a).\nIn summary, having reviewed the record and considered the assessment criteria for each of the\nItems cited above, I assess Respondent a total civil penalty of $35,000.\nPayment of the civil penalty must be made within 20 days of service. Federal regulations\n(49 C.F.R. § 89.21(b)(3)) require such payment to be made by wire transfer through the Federal\nReserve Communications System (Fedwire), to the account of the U.S. Treasury. Detailed\ninstructions are contained in the enclosure. Questions concerning wire transfers should be\ndirected to: Financial Operations Divisi","truncated":true,"body_characters":50920}