{"operation":"document","citation":"CPF 320101006M","title":"PANHANDLE EASTERN PIPELINE CO — Notice of Amendment","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2010-12-21","effective_on":null,"summary":"CLOSED notice of amendment citing 192.225(b), 192.231, 192.241(a), 192.241(b)(2), 192.245(a), 192.453, 192.463(a), 192.503(a), 192.605(b)(8), 192.612(b), 192.612(c)(2), 192.612(c)(3), 192.625(b), 192.707(d)(2), 192.727(d), 192.727(g), 192.735(a), 192.739(a), 192.739(a)(4), 192.751(a).","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-320101006m.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-320101006m.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-320101006m","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/320101006M","body":"Notice of Amendment involving PANHANDLE EASTERN PIPELINE CO. PHMSA's enforcement data identifies the cited regulations as 192.225(b),  192.231,  192.241(a),  192.241(b)(2),  192.245(a),  192.453,  192.463(a),  192.503(a),  192.605(b)(8),  192.612(b),  192.612(c)(2),  192.612(c)(3),  192.625(b),  192.707(d)(2),  192.727(d),  192.727(g),  192.735(a),  192.739(a),  192.739(a)(4),  192.751(a). The case was opened on 2010-12-21 and is reported as closed as of 2015-03-25. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n320101006M_Closure_03252015.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320101006M/320101006M_Closure_03252015.pdf\n\n320101006M_Closure_03252015_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320101006M/320101006M_Closure_03252015_text.pdf\n\n320101006M_NOA_12212010.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320101006M/320101006M_NOA_12212010.pdf\n\n320101006M_NOA_12212010_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320101006M/320101006M_NOA_12212010_text.pdf\n\n320101006M_Operator Response to NOA and Request for Hearing_01212011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320101006M/320101006M_Operator%20Response%20to%20NOA%20and%20Request%20for%20Hearing_01212011.pdf\n\n320101006M_Order Directing Amendment_12312012.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320101006M/320101006M_Order%20Directing%20Amendment_12312012.pdf\n\n320101006M_Order Directing Amendment_12312012_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320101006M/320101006M_Order%20Directing%20Amendment_12312012_text.pdf\n\n320101006M_Order Directing Amendment_12312012_text.pdf\n\nDECEMBER 31, 2012\nMr. Eric J. Amundsen\nVice President and Chief Asset Integrity Officer\nPanhandle Energy\n5051 Westheimer Road\nHouston, TX 77056\nRe: CPF No. 3-2010-1006M\nDear Mr. Amundsen:\nEnclosed please find the Order Directing Amendment issued in the above-referenced case. It\nmakes a finding of inadequate procedures, withdraws one allegation, and requires that Panhandle\nEnergy amend certain operating and maintenance procedures. When the amendment of\nprocedures has been completed, as determined by the Director, Central Region, this enforcement\naction will be closed. Service of the Order Directing Amendment by certified mail is effective\nupon the date of mailing as 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. Stephen M. Moore, Associate General Counsel, Panhandle Energy\n5051 Westheimer Rd, Houston, TX 77056\nMr. David Barrett, Director, Central Region, OPS\nMr. Alan Mayberry, Deputy Associate Administrator for Field Operations, OPS\nCERTIFIED MAIL – RETURN RECEIPT REQUESTED\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 )\nPanhandle Energy, a division of ) CPF No. 3-2010-1006M\nSouthern Union Company, )\n)\n)\n)\nRespondent. )\n___________________________________ )\nORDER DIRECTING AMENDMENT\nOn May 17–21, 2010, pursuant to 49 U.S.C. § 60117, representatives of the Pipeline and\nHazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS),\nconducted an inspection of the written operations and maintenance procedures of Panhandle\nEnergy (PE or Respondent) in Houston, Texas. PE is a division of Southern Union Company,\nwhich owns and operates more than 15,000 miles of pipeline that transport natural gas in the\nSouth and Midwest.1\nAs a result of the inspection, the Director, Central Region, OPS (Director), issued a Notice of\nAmendment (Notice) to Respondent dated December 21, 2010. In accordance with 49 C.F.R.\n§ 190.237, the Notice alleged 20 procedures were inadequate to assure safe operations and\nproposed that the procedures be amended to address the alleged inadequacies.\nPE responded to the Notice by letters dated January 21 and February 11, 2011. PE initially\ncontested only four of the allegations, requested a hearing on those items, and submitted\namended procedures for the remaining items. Both parties submitted pre-hearing materials on\nNovember 4, 2011. On November 8, 2011, the Director communicated by email that he\naccepted PE’s amendments for 10 of the 20 items, but did not accept them to address the\nremaining items for various reasons. Respondent contested the remaining items in additional\npre-hearing materials dated January 31, 2012, confirmed its intent to discuss them at the hearing,\nand provided additional explanations and further amendments.\nIn accordance with § 190.211, a hearing was held on February 16, 2012, in Kansas City,\nMissouri before the Presiding Official from the Office of Chief Counsel, PHMSA. At the\nhearing, both parties stipulated that based on the additional amendments submitted by PE, the\n1 http://www.panhandleenergy.com/comp_overview.asp (accessed Dec. 12, 2012). See also SEC Form 10-K,\nSouthern Union Company at 3-5 (Feb. 2012). Panhandle Energy includes its subsidiaries Panhandle Eastern Pipe\nLine, Trunkline Gas, Trunkline LNG, Sea Robin Pipeline, and Florida Gas Transmission.\n\n\n\n2\ncompany had satisfied 13 of the 20 items. The remaining allegations in Items 1, 5, 7, 10, 15, 19,\nand 20 were discussed at the hearing.\nAfter the hearing, Respondent submitted post-hearing materials dated April 16 and 22, 2012.\nRespondent stated that the parties had resolved several additional items, leaving only Items 10\nand 19 contested and unresolved. Pursuant to § 190.213(b)(4), the Director submitted a post-\nhearing recommendation concurring that only Items 10 and 19 remained contested and\nunresolved.\nUncontested/Resolved Items\nRespondent has submitted amended procedures to address the inadequacies alleged in Items 1-9,\n11-18, and 20 of the Notice. The alleged inadequacies were as follows:\n49 C.F.R. §§ 192.13(c) and 192.503(a) (Item 1) – PE’s procedures for substantiating the\nmaximum allowable operating pressure (MAOP) of new pipe did not specify the amount\nof new “pre-tested” pipe that is allowed to be installed during a maintenance project and\ndid not specify the amount that would require a post-construction hydrostatic test.\n49 C.F.R. § 192.225(b) (Item 2) – PE’s welding procedures did not require the company\nto retain records of qualifying tests.\n49 C.F.R. § 192.231 (Item 3) – PE’s welding procedures did not define adverse weather\nconditions that would require protection to ensure welding quality is not impaired.\n49 C.F.R. § 192.241(a) (Item 4) – PE’s procedures for the inspection of welds did not\nrequire its inspectors to be qualified to conduct visual weld inspections.\n49 C.F.R. § 192.241(b)(2) (Item 5) – PE’s procedures for the inspection of welds did not\ndefine the number of welds that make nondestructive testing “impractical.”\n49 C.F.R. § 192.245(a) (Item 6) – PE’s procedures for the repair and removal of weld\ndefects did not reference the correct sections of API Standard 1104 (incorporated by\nreference, see § 192.7) for repairing and removing a weld that is unacceptable under\n§ 192.241(c).\n49 C.F.R. §§ 192.605(b)(1) and 192.612(b) (Item 7) – PE’s procedures for assessing the\nrisk of pipelines in the Gulf of Mexico and its inlets did not contain sufficient criteria and\nguidance to ensure consistent application.\n49 C.F.R. §§ 192.605(b)(1) and 192.612(c)(2) (Item 8) – PE’s procedures for underwater\ninspection and reburial of pipelines in the Gulf of Mexico and its inlets did not\nadequately describe the marking that is required when the operator discovers a pipeline\nhas become exposed or poses a hazard to navigation.\n\n\n\n3\n49 C.F.R. §§ 192.605(b)(1) and 192.612(c)(3) (Item 9) – PE’s procedures for underwater\ninspection and reburial of pipelines in the Gulf of Mexico and its inlets did not require the\noperator to bury an underwater pipeline that becomes exposed or poses a hazard to\nnavigation.\n49 C.F.R. §§ 192.605(b)(1) and 192.707(d)(2) (Item 11) – PE’s procedures for placing\nand maintaining line markers did not require markers to have a current telephone number\nwhere the operator can be reached at all times; rather, the procedures permitted markers\nto list a collect call number that is no longer available.\n49 C.F.R. §§ 192.605(b)(1) and 192.727(d) (Item 12) – PE’s procedures for\ndiscontinuing service to a customer did not require the operator to utilize one of the three\nmethods in the regulation to prevent the flow of gas.\n49 C.F.R. §§ 192.605(b)(1) and 192.727(g) (Item 13) – PE’s procedures for the\nabandonment of facilities did not require a report to be filed with PHMSA for each\nabandoned offshore pipeline or onshore pipeline facility that crosses a commercially\nnavigable waterway.\n49 C.F.R. §§ 192.605(b)(1) and 192.735(a) (Item 14) – PE’s procedures for compressor\nstations did not identify combustible materials that must be stored a safe distance from\nthe compressor building and did not specify the quantity of combustible materials that\nmay be required for everyday use.\n49 C.F.R. §§ 192.605(b)(1) and 192.739(a) (Item 15) – PE’s procedures for inspecting\nand testing pressure limiting and regulating stations did not require fuel gas regulators\n(“Category 2” regulators) to be inspected and tested annually.\n49 C.F.R. §§ 192.605(b)(1) and 192.739(a)(4) (Item 16) – PE’s procedures for inspecting\nand testing pressure limiting and regulating stations did not require pressure control\ndevices to be inspected to ensure they are properly protected from dirt, liquids, and other\nconditions that may prevent proper operation.\n49 C.F.R. §§ 192.605(b)(1) and 192.751(a) (Item 17) – PE’s procedures for preventing\naccidental ignition did not require the removal of certain potential ignition sources, such\nas cell phones, in areas where a hazardous amount of gas is being vented into open air.\n49 C.F.R. §§ 192.605(b)(2) and 192.453 (Item 18) – PE’s corrosion control procedures,\nincluding those for the design, installation, operation, and maintenance of cathodic\nprotection systems, did not require the procedures to be carried out by, or under the\ndirection of, a person qualified in pipeline corrosion control methods.\n49 C.F.R. § 192.605(b)(8) (Item 20) – PE’s procedures for maintenance and normal\noperations did not contain detailed provisions requiring periodic review of the work done\nby employees to determine the effectiveness and adequacy of the procedures.\n\n\n\n4\nAfter reviewing the materials presented in writing and at the hearing, I find that Respondent’s\nprocedures were inadequate as alleged in the Notice, but that Respondent has successfully\namended its procedures to address the inadequacies. Accordingly, Items 1-9, 11-18, and 20 of\nthe Notice have been satisfied and Respondent is not ordered to take any further action with\nregard to those Items.\nContested/Unresolved Items\nIn its written submissions and at the hearing, Respondent contested the inadequacy of its\nprocedures as alleged in Items 10 and 19 of the Notice. The alleged inadequacies are as follows:\nItem 10: The Notice alleged that Respondent’s procedures are inadequate with regard to\n§ 192.625(b), which states:\n§ 192.625 Odorization of gas.\n(a) A combustible gas in a distribution line must contain a natural\nodorant or be odorized so that at a concentration in air of one-fifth of the\nlower explosive limit, the gas is readily detectable by a person with a\nnormal sense of smell.\n(b) After December 31, 1976, a combustible gas in a transmission line\nin a Class 3 or Class 4 location must comply with the requirements of\nparagraph (a) of this section unless:\n(1) At least 50 percent of the length of the line downstream from that\nlocation is in a Class 1 or Class 2 location;\n(2) The line transports gas to any of the following facilities which\nreceived gas without an odorant from that line before May 5, 1975;\n(i) An underground storage field; (ii) A gas processing plant; (iii)\nA gas dehydration plant; or (iv) An industrial plant using gas in a\nprocess where the presence of an odorant:\n(A) Makes the end product unfit for the purpose for which it is\nintended;\n(B) Reduces the activity of a catalyst; or\n(C) Reduces the percentage completion of a chemical reaction;\n(3) In the case of a lateral line which transports gas to a distribution\ncenter, at least 50 percent of the length of that line is in a Class 1 or Class\n2 location; or\n(4) The combustible gas is hydrogen intended for use as a feedstock in\na manufacturing process.\nThe Notice alleged that PE’s procedures are inadequate because they do not include provisions\nfor determining when transmission pipelines, including laterals, that are partially in a Class 3 or\nClass 4 location are required to be odorized.\nIn its written submissions and at the hearing, PE explained that its procedures contain provisions\nfor determining when odorization is required, in particular Standard Operating Procedure B.12,\nEvaluating Class Location Changes, in Step 3 of Section 7.3, “Determine Subsequent Actions.”\n\n\n\n5\nRespondent also noted that Step 7 requires the identification of Class 3 or Class 4 areas that\nrequire odorization and the procedure includes language from the regulation to guide that\nidentification process. To clarify its procedures, PE added Appendix D to Procedure B.12\nconsisting of guidance that repeats the exceptions in § 192.625(b). Respondent also amended its\nprocedures to make clear that it uses an electronic system for evaluating Class location and that\npersonnel must look at the records to identify Class location and pipeline lengths.2 Respondent\nexplained that the amended procedures require the operator to calculate the percentage of pipe\nthat is in a Class 3 or Class 4 area and then use the criteria in the regulation to evaluate whether\nodorization is required.\nAt the hearing, OPS alleged that PE’s amended procedures were still inadequate because they do\nnot describe how PE evaluates its pipelines to determine whether the lines need to be odorized.\nOPS suggested that PE should amend its procedures to be consistent with a 2009 final order\nissued by PHMSA.\n3 The Presiding Official asked whether the alleged procedural inadequacy\nconcerned the manner in which PE determined class location, the manner in which PE calculated\nthe length of lateral lines, or some other issue. OPS responded that the issue was not how PE\ndetermined class location, but OPS did not further explain the inadequacy other than to restate\nthat details were missing concerning how PE evaluates lateral lines to determine whether they\nneed to be odorized.4\nIn its post-hearing submission, PE claimed that after communicating further with OPS, the\ncompany understood the disagreement concerns how the company defines a lateral line for\npurposes of determining whether at least 50 percent of a lateral is located in a Class 1 or Class 2\narea under § 192.625(b)(3). In this regard, Respondent explained how its procedures designate\nthe length of a lateral line and contested the manner in which OPS sought to apply the 2009 final\norder to PE’s procedures.\nNormally, gas in a transmission line in a Class 3 or Class 4 location must be odorized pursuant to\n§ 192.625(b). In the case of a lateral transmission line which transports gas to a distribution\ncenter, § 192.625(b)(3) provides that odorization is not required if at least 50 percent of “the\nlength of that line” is in a Class 1 or Class 2 location.5 For an operator to determine whether a\nlateral meets this exception, the operator must calculate the length of the lateral and determine if\n50 percent or more of the length is in a Class 1 or Class 2 location.\nThe 2009 final order issued in ANR Pipeline evaluated an operator’s method for calculating the\nlength of its laterals for purposes of applying the exception. ANR’s pipeline system consisted of\nan interstate gas transmission line and a subsidiary pipeline system, or lateral system, that\nbranched away from the interstate line at a single departure point. The lateral system delivered\n2 PE’s Response at 4 and Exhibit Item 10 (Jan. 21, 2011).\n3 See ANR Pipeline Co., CPF No. 3-2007-1006, 2009 WL 5538653 (Dec. 4, 2009). Final orders are also available at\nhttp://primis.phmsa.dot.gov/comm/reports/enforce/Enforcement.html; click “Enforcement Actions.”\n4 Hearing transcript at 41-44.\n5 The intent of this exception was to exclude short segments of pipeline in predominantly rural areas where the\nlikelihood of someone detecting a leak of odorized gas was lower. Odorization of Gas in Transmission Lines, 40\nFed. Reg. 20,279, 20,281 (May 9, 1975).\n\n\n\n6\ngas through a web of transmission lines, some branching off from others, all leading to different\ndistribution centers. The source of gas at each end point on the lateral system could be traced\nback through commonly-shared branches to the single departure point on the interstate\ntransmission line.\nANR calculated the length of each lateral line from its end point at the distribution facility all the\nway back to the single departure point on the interstate transmission line. As a result, the same\nupstream mileage shared by multiple lateral lines was factored into the length of each lateral.\n6\nPHMSA concluded this methodology was not allowed because it “overweighted” mileage in\nClass 1 and Class 2 locations, skewing the results in favor of finding each lateral had more than\n50 percent of its length in a Class 1 or Class 2 location and artificially inflating the number of\nlines meeting the exception in § 192.625(b)(3).\nIn the current proceeding, OPS has sought to apply the same rationale to PE’s procedures. After\nreviewing Respondent’s amended procedures, however, I find they do not present the same\nproblem addressed in the ANR Pipeline case. There is no indication that PE’s procedures permit\ncalculating the length of individual lateral lines from their respective end points at a distribution\nfacility back to their common point of origin, double counting upstream mileage. To the\ncontrary, Respondent explained in its post-hearing submission, and demonstrated through the use\nof a diagram included in its amended procedures, that it calculates the length of each lateral line\nfrom its end point at a distribution facility to its connection with the first distinct upstream\ntransmission line that serves as the source of gas for the lateral line (as established when the\nlateral was constructed).7 Since PE’s procedures do not employ the improper methodology that\nwas found to be a violation in ANR Pipeline, I find the 2009 final order does not support finding\nPE’s procedures are inadequate.\nIn its post-hearing submission, Respondent contested what it believed was a requirement set\nforth in the ANR Pipeline decision that operators must recalculate the length of a lateral line if a\nnew pipeline is constructed from the lateral to another distribution center.8 Respondent argued\nthat recalculating the length of the original lateral from its distribution center to a new\nintersection would be burdensome for operators and unnecessary for safety if there has been no\nchange to the class location of the original lateral.\nThe question of whether an operator must recalculate the length of a lateral as a result of new\nconstruction was not explored under the specific facts in ANR Pipeline. In addition, OPS has not\nalleged in the Notice or at the hearing that Respondent’s procedures are inadequate with regard\nto this issue. Accordingly, it is not necessary to address this issue raised by Respondent.\nPE also argued that it would be improper for PHMSA to interpret § 192.625(b)(3) in the current\nproceeding because there is a pending rulemaking that proposes to alter the regulation.9\n6 ANR Pipeline at 5-6.\n7 PE’s Post-hearing Submission, Exhibit B (Apr. 16, 2012).\n8 PE’s Post-hearing Submission at 3.\n9 See Miscellaneous Changes to Pipeline Safety Regulations, 76 Fed. Reg. 73,570, 73,574, 73,579 (proposed\nNov. 29, 2011) (proposing to clarify § 192.625(b)(3) to avoid any inconsistent application).\n\n\n\n7\nGenerally, administrative agencies are not precluded from announcing or refining a regulatory\ninterpretation in an adjudicative proceeding. I find no reason to withhold rendering a decision\nregarding the regulation in effect at the time of the allegation.\nHaving reviewed the record, I find PE’s amended procedures include provisions for determining\nwhen transmission pipelines, including laterals, that are partially in a Class 3 location are\nrequired to be odorized. There is insufficient evidence in the record to conclude that PE’s\namended procedures are inadequate to assure safe operation. Therefore, this item is withdrawn.\nItem 19: The Notice also alleged that Respondent’s procedures are inadequate with regard to\n§ 192.463(a), which states:\n§ 192.463 External corrosion control: Cathodic protection.\n(a) Each cathodic protection system required by this subpart must\nprovide a level of cathodic protection that complies with one or more of\nthe applicable criteria contained in appendix D of this part. If none of\nthese criteria is applicable, the cathodic protection system must provide a\nlevel of cathodic protection at least equal to that provided by compliance\nwith one or more of these criteria.\nThe Notice alleged that PE’s procedures are inadequate because they do not properly consider\nvoltage (IR) drop when measuring cathodic protection levels to ensure compliance with the\napplicable criteria contained in Appendix D of Part 192. Specifically, the Notice alleged that\nwhen PE obtains readings that demonstrate there is inadequate cathodic protection after\naccounting for IR drop, such as data from instant-off readings, Respondent’s procedures do not\nrequire the company to remediate the deficiency or verify that another criterion has been met.\nAt the hearing, OPS explained that Respondent uses the -850 mV criterion for determining if\ncathodic protection is adequate. The criterion requires operators to consider IR drop for valid\napplication. OPS produced records from a close interval survey PE performed in 2009 showing\nlocations on the pipeline where instant-off readings were less negative than -850 mV. OPS\nexplained that using instant-off is the best method for considering IR drop, and that if cathodic\nprotection levels are less negative than -850 mV when IR drop is considered, the applicable\ncriterion has not been met. OPS alleged that PE’s procedures are inadequate because they do not\nrequire the operator to take corrective action to remediate the low levels, or to meet one of the\nother criteria.\nAt the hearing and in its written submissions, PE contested the allegation that its procedures are\ninadequate. PE contested OPS’s assertion that levels of cathodic protection are inadequate if the\ninstant-off reading is less negative than -850 mV. PE also contested the assertion that instant-off\nreadings are the best estimate available for considering IR drop. PE explained that Standard\nOperating Procedure D.22, Application of Cathodic Protection Criteria, addresses the applicable\nregulatory requirements. In accordance with those procedures, PE noted that it properly\naddressed the 2009 survey readings and that more recent survey results from 2011 indicate\ncathodic protection levels are as required.\n\n\n\n8\nBackground\nOperators are required to have written procedures for cathodic protection systems to protect their\nmetallic pipelines from external corrosion.10 A cathodic protection system with an impressed\ncurrent prevents external corrosion on buried pipelines by applying a direct electric current to the\nmetal of the pipeline in an amount sufficient to prevent the loss of metal from the pipeline to the\nsurrounding environment.11 If insufficient current is provided, corrosion can result.\nSection 192.463 requires operators to use certain reference criteria for measuring the flow of\nelectric current to or from their pipelines (pipe-to-soil potential) to determine if cathodic\nprotection is adequate. One of the criteria PE uses is the -850 mV criterion described in\nAppendix D of Part 192, section I, paragraph (A)(1): “A negative (cathodic) voltage of at least\n0.85 volt, with reference to a saturated copper-copper sulfate half cell. Determination of this\nvoltage must be made with the protective current applied, and in accordance with sections II and\nIV of this appendix.” This is commonly known as the -850 mV current applied or “on” criterion.\nTo accurately determine if the pipe-to-soil potential meets this criterion, operators must consider\nthe IR drop. IR drop is the difference between the voltage at the top of the pipe and the voltage\nat the surface of the earth caused by the electrical resistance of the soil in which the pipeline is\nburied. Section II of Appendix D states: “Voltage (IR) drops other than those across the\nstructure-electrolyte boundary must be considered for valid interpretation of the voltage\nmeasurement.” If IR drop is not properly considered, cathodic protection may appear to meet the\n-850 mV criterion when, in fact, it does not.\nAlthough Appendix D of Part 192 does not explicitly define how IR drop “must be considered,”\nRespondent noted that section 6.2.2.1.1 of National Association of Corrosion Engineers (NACE)\nStandard SP-0169 (2007) states that “consideration [of IR drop] is understood to mean the\napplication of sound engineering practice in determining the significance of voltage drops by\nmethods such as: [1] measuring or calculating the voltage drop(s); [2] reviewing the historical\nperformance of the CP system; [3] evaluating the physical and electrical characteristics of the\npipe and its environment; and [4] determining whether or not there is physical evidence of\ncorrosion.” Part 192 does not incorporate NACE Standard SP-0169 by reference, but the criteria\nin Appendix D were based on and were substantially the same as those in the 1969 issue of that\nNACE standard.\n12\nUsing Data from Instant-Off Readings to Consider IR Drop\nOne method of considering IR drop is to measure or calculate the IR drop by interrupting the\ncurrent and taking an instant-off reading. IR drop can be “minimized or eliminated by\ninterrupting all of the direct current sources of the CP system and measuring the instantaneous\n10 §§ 192.605(b)(2), 195.402(c)(3).\n11 Kinder Morgan Energy Partners, L.P., CPF No. 4-2006-5023, at 6-7, 2010 WL 6531634 (Aug. 31, 2010).\n12 Requirements for Corrosion Control, 36 Fed. Reg. 12,297, 12,299, 12,301 (Jun. 30, 1971). Cathodic protection\nregulations for hazardous liquid pipelines do incorporate NACE Standard SP-0169 (2007) by reference. See\n§§ 195.3, 195.571.\n\n\n\n9\noff-potential . . . . The difference between the on- and the off-potential indicates the magnitude of\nthe IR voltage drop error when the measurement is made with the protective current applied.”13\nAt the hearing, OPS contended that instant-off readings of less than -850mV on Respondent’s\npipeline indicated inadequate cathodic protection. In response, PE argued that the readings did\nnot indicate inadequate cathodic protection because the “on” reading was -850 mV or more.\nAlthough not cited by either party, for consistency I must consider prior PHMSA enforcement\ndecisions that evaluated this issue. In 2010, PHMSA found a pipeline operator had failed to\nproperly consider IR drop based on evidence of survey readings showing instant-off potentials\nthat did not meet the -850 mV criterion.14 In another case issued the same year, PHMSA stated\nthat the use of close interval surveys and instant-off readings “means that readings with the\ncurrent applied must be at least as negative as -850 mV plus the negative of the IR drop\ndetermined for each particular location.”15 Even as early as 1996, the agency issued a letter of\nconcern explaining that “when the pipe-to-soil potential measured directly over the pipe is -850\nmV, the IR drop must be zero or the protective potential on the pipe will be less than -850\nmV.”16 The agency stated that unless the operator can demonstrate IR drop is zero or\ninsignificant, “the required level of protection is not achieved.” In 1998, PHMSA warned that\ninstant-off readings of -852mV “barely meet” the -850 mV criterion.17\nPHMSA’s enforcement history indicates it is the agency’s position that cathodic protection is\ninadequate if the instant-off reading from an interrupted current is less negative than -850 mV.\nPE argued that operators are not even required to take instant-off readings for several reasons.\nFirst, PE argued that the regulations do not require instant-off. Second, PE argued that\ninterpretations issued by PHMSA state that instant-off is not required. Finally, PE argued there\nis no technical support for finding instant-off is the best or even the preferred method for\nconsidering IR drop.\nWith regard to PE’s position that the regulations do not require instant-off, PE argued that taking\n“on” and instant-off readings are actually two separate criteria and that under the regulations,\noperators need only meet one of the criteria in Appendix D of Part 192.\nPE’s position that operators need only meet one of the criteria in Appendix D is supported by\n§ 192.463, which states that cathodic protection systems must provide a level of cathodic\nprotection “that complies with one or more of the applicable criteria.” (emphasis added.) This\nposition also is reflected in a 1992 interpretation cited by Respondent, which stated that “no\n13 A. W. Peabody, Peabody’s Control of Pipeline Corrosion at 50-51 (2d ed. 2001), included in OPS’s Pre-hearing\nSubmission.\n14 BP Pipelines (North America), Inc., CPF No. 4-2007-5003, at 3-5, 2010 WL 6518288 (Jul. 19, 2010).\n15 Sunoco Pipeline, L.P., CPF No. 4-2007-5040, at 10, 2010 WL 5761108 (Dec. 16, 2010).\n16 Texas-New Mexico Pipeline Co., CPF No. 4-1996-5018-C (formerly 46518C), 1996 WL 34390103\n(Dec. 24, 1996).\n17 Trans Mountain Oil Pipeline Corp., CPF No. 5-1998-5009-W (formerly 58509W), at 2-3, 1998 WL 35166459\n(May 5, 1998).\n\n\n\n10\nfurther test data are required if one of the criteria is met.”18 Appendix D of Part 192 does not\nexplicitly list instant-off or any other specific methods for considering IR drop.\nAlthough operators need only meet one of the criteria, I reject Respondent’s suggestion that\ntaking “on” and instant-off readings necessarily represent two completely separate criteria. Data\nfrom both readings can be used to determine compliance with one criterion: the -850 mV “on”\ncriterion. That is because the -850 mV criterion requires operators to consider IR drop for valid\ninterpretation of the voltage measurement with the current applied. Instant-off readings are taken\nby pipeline operators for the purpose of considering IR drop.19\nWith regard to PE’s position that agency interpretations demonstrate instant-off is not required,\nRespondent cited two interpretations. The first interpretation, from 1985, described a (then) new\nenforcement policy that OPS would accept an operator’s consideration of IR drop, even if the\noperator had not taken instant-off readings.20 One exception, OPS explained, was if a corrosion\nleak had occurred, at which point the operator “must measure the level of cathodic protection\n(polarized potential) at the soil to metallic structure interface.” If the level of cathodic protection\nafter measuring IR drop “is less than that required by the regulations,” the agency could take\nenforcement for failing to properly considered IR drop. A second interpretation letter, issued in\n1991, repeated this enforcement policy.21\nI agree the interpretation letters do not suggest that operators are always required to use instant-\noff to consider IR drop. The interpretations do confirm that operators must be able to\ndemonstrate the adequacy of corrosion protection and how the operator considers IR drop, and\nthat operators may be subject to enforcement action if they do not properly consider IR drop.22\nWith regard to PE’s position that instant-off is not the best method or even the preferred method\nfor considering IR drop, I agree there is not sufficient evidence in the record of this case to prove\nthat instant-off is the “best” method to consider IR drop. With regard to whether instant-off is\npreferred by PHMSA, however, I must consider PHMSA’s enforcement history to the extent the\nagency has taken a position on the issue.\nIn a 2009 decision, PHMSA found a violation when the operator had not conducted interrupted\nsurveys on its entire system.\n23 In that case, the operator claimed it had used other methods to\nconsider IR drop, such as visual observation and measurement of pipe wall thickness, in-line\n18 PHMSA Interpretation #PI-92-062 issued to Mr. Dan H. Weaklend (Nov. 23, 1992). PHMSA interpretations are\navailable at http://www.phmsa.dot.gov/pipeline/regs/interps.\n19 PE argued that instant-off readings can also be used separately for the -850 mV “polarized” criterion listed in\n6.2.2.1.2 of NACE Standard SP-0169. Since Appendix D of Part 192 does not list that criterion, PE argued that\nPHMSA cannot require its use. Notwithstanding PE’s assertion, however, PHMSA recognizes the appropriate use\nof instant-off readings to consider IR drop when using the -850 mV “on” criterion.\n20 PHMSA Interpretation #PI-85-001 issued to Mr. Lawrence Ogden (Mar. 18, 1985).\n21 PHMSA Interpretation #PI-91-025 issued to Mr. Dan H. Weaklend (Aug. 29, 1991).\n22 Notwithstanding the enforcement policy from the mid-1980s, PHMSA may always verify compliance with the\nrequirement in the regulation to properly consider IR drop, even absent a corrosion leak.\n23 Enterprise Products Operating, LLC, CPF No. 4-2007-5015, at 4-7, 2009 WL 5538652 (Dec. 2, 2009).\n\n\n\n11\ninspection (ILI), and leak history. PHMSA found these other methods were either\nundocumented or did not produce relevant data to support a determination as to the adequacy of\ncathodic protection. In particular, PHMSA noted the operator had not submitted “any other\ndocumentation, such as reports or summaries, that document the use of all these methods in a\nmanner that would enable Respondent to determine whether its cathodic protection systems\ncomplied with applicable standards.”\nIn another case, PHMSA found that even though the operator’s procedures included methods for\nconsidering IR drop identical to the NACE standard, the operator had failed to use an interrupted\nsurvey or document the use of another acceptable method to consider the significance of IR drop\non the entire pipeline.24 In 2010, PHMSA found that reviewing the historical performance of the\ncathodic protection system and the absence of reportable spills caused by corrosion did not\ndemonstrate proper consideration of IR drop.25 Even as early as 1997, PHMSA warned that an\noperator was not properly considering IR drop, because it was not taking instant-off readings or\nperforming some other test.26 In 1998, PHMSA issued a letter of concern stating that “Instant\nOff is the preferred method for obtaining IR Drop free readings.”27\nThe agency’s enforcement history over many years demonstrates that PHMSA considers instant-\noff readings to be the preferred method of considering IR drop because that method provides\nprobative data as to the amount of the IR drop at any given location on the pipeline. Other\nevaluation methods have not been found to be acceptable on their own, at least based on the\nspecific facts presented in those cases. While the prior enforcement decisions do not foreclose\nthe use of other methods of considering IR drop, they do show that other such methods must be\ndocumented and must produce relevant data to support a determination about the present level of\ncathodic protection on the pipe.\nEvaluation of Respondent’s Procedures\nIn its written submissions and at the hearing, PE contended that its procedures address the\napplicable regulatory requirements and industry best practices. In particular, PE explained that\nProcedure D.22 allows the “identical” use of the four options listed in section 6.2.2.1.1 of NACE\nStandard SP-0169.28 Respondent also contended that its procedures are technically superior to\nthose proposed by OPS because they provide for consideration of all factors related to the pipe\nsegment, allow the use of (but do not require) instant-off to measure IR drop, and recognize that\npipe-to-soil potentials contain error due to IR drop.\nHaving reviewed Respondent’s procedures, I find that PE uses the -850 mV criterion to\ndetermine the adequacy of its cathodic protection systems. Using this criterion, PE must\n24 Marathon Ashland Pipe Line, LLC, CPF No. 5-2003-5013, at 1-3, 2006 WL 3825308 (Feb. 16, 2006).\n25 BP Pipelines (North America), Inc., CPF No. 4-2007-5003, at 4-5, 2010 WL 6518288 (Jul. 19, 2010).\n26 Plantation Pipeline Co., CPF No. 2-1997-0509 (formerly 27509W), at 2, 1997 WL 34614818 (Dec. 8, 1997).\n27 Williams Gas Pipeline – Central, CPF No. 5-1998-0020-C (formerly 58020C), at 3, 1998 WL 35166444\n(Oct. 21, 1998).\n28 PE’s Post-hearing Submission 5.\n\n\n\n12\nconsider IR drop to obtain an accurate reading of the pipe-to-soil potential. Section 7.3 of PE’s\nProcedure D.22 permits the use of close interval surveys and instant-off readings, which PHMSA\nrecognizes as the preferable method to consider IR drop.29 PE’s procedures also permit\nconsidering IR drop by comparing historical levels of cathodic protection with physical evidence\nfrom the pipeline “to determine whether corrosion has occurred.” PE may compare soil\ncorrosiveness with physical evidence “to determine whether corrosion has occurred.” Finally,\nPE may obtain physical evidence of corrosion from leak history, pipe inspection reports, and ILI\ndata.\nWith regard to the use of interrupted surveys, PHMSA considers cathodic protection inadequate\nat a given location if the instant-off reading from an interrupted current is less negative than -850\nmV. At many locations on Respondent’s pipeline in 2009, the instant-off readings demonstrate\nthat cathodic protection was less negative than the -850 mV standard. Although PE’s procedures\nrecognize that pipe-to-soil potentials contain error due to IR drop, the procedures only require\nadjustment of the pipe-to-soil potentials to account for IR drop when operational or historic data\nindicates there is “ongoing corrosion activity.”30 Because Respondent’s procedures do not\nrecognize that instant-off survey readings of less than -850mV require additional protection (or\ncompliance with another criterion), I find the procedures are inadequate.\nOther Issues Raised by Respondent\nPE suggested that if operators were required to consider IR drop by taking instant-off readings,\nthey “would no longer be allowed” to use other methods for considering IR drop, resulting in\ntechnically unsound and potentially erroneous determinations of effective corrosion control.31\nI find this argument implausible, since operators using instant-off readings to consider IR drop\nmay still use other methods, so long as the methods are documented in the operators’ procedures\nin a manner that demonstrates the methods result in data relevant to considering IR drop and the\nlevel of cathodic protection on the pipe. For example, a documented review of leak history can\nshow where a pipeline has not received adequate protection.\nPE also argued that the Notice and related testimony indicate the company’s procedures for\nconsidering IR drop are adequate “except when instant-off data is collected.”32\nAt the hearing, however, OPS stated that PE should not infer there were no other issues.33 I find\nthe allegations of inadequate procedures in the Notice do not imply PE’s procedures are\notherwise adequate.\n29 PE’s Pre-hearing Submission, Exhibit 19-A-3 (Nov. 4, 2011).\n30 The methods included in the NACE standard are written\n31 PE’s Post-hearing Submission at 7-8.\n32 PE’s Post-hearing Submission at 7.\n33 Hearing transcript at 57.\n\n\n\n13\nPE further argued that instant-off readings are not always collected on its system. For example, a\nsignificant ","truncated":true,"body_characters":44714}