{"operation":"document","citation":"0900006481a1780f","title":"U.S. DOT/PHMSA - Final Rule - Regulatory Impact Analysis","source_type":"rulemaking","agency":"Pipeline and Hazardous Materials Safety Administration","status":"current","official":true,"published_on":null,"effective_on":null,"summary":"Regulatory Impact Analysis: Final Rule Pipeline Safety: Responsibility to Conduct Inspections, Type B Gathering Lines Leak Surveys, and other Pipeline Safety Changes PHMSA-2010-0026 Office of Pipeline Safety Pipeline and Hazardous Materials Safety Administration (PHMSA) U.S. Department of Transportation February 2015 1 February 2015 Executive Summary This package of regulatory changes addresses errors and inconsistencies in the current regulations, provides additional clarifications, incorporates industry standards, and responds to an NTSB safety recommendation and petitions for rulemaking. Many of the revisions are small changes...","machine_formats":{"json":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006481a1780f.json","markdown":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006481a1780f.md"},"app_url":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006481a1780f","source_url":"https://downloads.regulations.gov/PHMSA-2010-0026-0053/attachment_1.pdf","body":"<<<PAGE 1>>>\n\nRegulatory Impact Analysis: Final Rule\nPipeline Safety: Responsibility to Conduct Inspections, Type B Gathering Lines Leak\nSurveys, and other Pipeline Safety Changes\nPHMSA-2010-0026\nOffice of Pipeline Safety\nPipeline and Hazardous Materials Safety Administration (PHMSA)\nU.S. Department of Transportation\nFebruary 2015\n1\n\n<<<PAGE 2>>>\n\nFebruary 2015\nExecutive Summary\nThis package of regulatory changes addresses errors and inconsistencies in the current\nregulations, provides additional clarifications, incorporates industry standards, and responds to\nan NTSB safety recommendation and petitions for rulemaking. Many of the revisions are small\nchanges that would not lead to substantial changes in regulatory requirements, operator practices,\nor overall costs and benefits.\nBenefit-Cost Analysis\nAnnual compliance costs are estimated to be $0.55 million. Annual safety benefits are not as\neasily quantifiable, but are estimated at $25,222 in avoided incident costs, plus many intangible\nbenefits from the improved clarity and consistency of regulations and better information for\nPHMSA on potential safety issues. Although the quantifiable benefits do not exceed the\nestimated costs, PHMSA believes that the many non-quantifiable benefits of these changes\nsignificantly outweigh the cost of compliance.\nRegulatory Flexibility Act Analysis\nThe Regulatory Flexibility Analysis found that the rule could affect a substantial number of\nsmall entities because of the market structure of the gas and hazardous liquids pipeline industry,\nwhich includes many small entities. However, these impacts would not be significant.\nUnfunded Mandates Act Analysis\nPHMSA determined that the rule would not impose annual expenditures on State, local, or tribal\ngovernments of the private sector in excess of $153 million, and thus does not require an\nUnfunded Mandates Act analysis.1\n1 The Unfunded Mandates Act threshold was $100 million in 1995. Using the non-seasonally adjusted CPI-U (Index\nseries CUUR0000SA0), that number is $153 million in 2013 dollars.\n2\n\n<<<PAGE 3>>>\n\nFebruary 2015\n1 Introduction\nThe Pipeline and Hazardous Materials Safety Administration (PHMSA) is proposing a package\nof changes to the pipeline safety regulations. The changes would correct errors, address\ninconsistencies, and respond to rulemaking petitions.\nRequirements in several subject matter areas would be affected, including clarifying the\nresponsibility to conduct construction inspections, the performance of leak surveys for Type B\ngathering lines, qualification requirements for plastic pipe joiners, modifying mill hydrostatic\ntests for pipe to operate at alternative maximum allowable operation pressure (MAOP),\nregulating the transportation of ethanol by pipeline, the transportation of pipe, offshore pipeline\ncondition reports, calculating pressure reductions for hazardous liquid pipeline integrity\nanomalies, testing components other than pipe installed in low- pressure gas pipelines,\nalternative MAOP Notifications, codifying the National Pipeline Mapping System (NPMS),\nincluding welding operators as qualified to use welding equipment, explaining test requirements\nfor components fabricated by welding, and editorial changes.\nThis report analyzes the benefits and costs of the regulatory changes as required by Section 1 of\nExecutive Order 12866 (as amended by E.O.’s 13258 (2002), 13422 (2007), and 13497 (2009))\nand Section 1 of E.O. 13563 (2011).\n2 Executive Orders 12866 and 13563 require agencies to\nregulate in the “most cost-effective manner,” make a “reasoned determination that the benefits of\nthe intended regulation justify its costs,” and develop regulations that “impose the least burden\non society.”\nAnalysis of the potential impacts on small entities is also required by the Regulatory Flexibility\nAct. The Regulatory Flexibility Act analysis is also included in this document (see Section 8).\n2 Background\nPHMSA, pipeline operators, and others have identified certain errors, inconsistencies, updates to\nstandards incorporated by reference, and other deficiencies in the Pipeline Safety Regulations.\nAs such, PHMSA is proposing to make a set of miscellaneous changes to the Pipeline Safety\nregulations concerning the following subjects, which are described in more detail in sections 3.1\nto 3.12 below:\n• Responsibility to Conduct Construction Inspections\n• Leak Surveys for Type B Gathering Lines\n2 The text of E.O. 12866 can be found here: http://www.archives.gov/federal-register/executive-\norders/pdf/12866.pdf and E. O. 13563 here:\nhttp://www.whitehouse.gov/sites/default/files/omb/inforeg/eo12866/eo13563_01182011.pdf\n3\n\n<<<PAGE 4>>>\n\nFebruary 2015\n• Qualifying Plastic Pipe Joiners\n• Mill Hydrostatic Tests for Pipe to Operate at Alternative Maximum Allowable Operation\nPressure (MAOP)\n• Regulating the Transportation of Ethanol by Pipeline\n• Transportation of Pipe\n• Offshore Pipeline Condition Reports\n• Calculating Pressure Reductions for Hazardous Liquid Pipeline Integrity Anomalies\n• Testing Components Other than Pipe Installed in Low- Pressure Gas Pipelines\n• Alternative MAOP Notifications\n• National Pipeline Mapping System (NPMS)\n• Welders vs. Welding Operators\n• Components Fabricated by Welding\n• Editorial Amendments\n3 Identification of the Problem and the Need for the Rule\nUnder the Federal Pipeline Safety Laws, 49 U.S.C. 60101 et seq., the Secretary of Transportation\nmust prescribe minimum safety standards for pipeline transportation and for pipeline facilities.\nThe Secretary has delegated this authority to the PHMSA Administrator (49 CFR 1.53(a)). The\nrule would create changes in the regulations consistent with the protection of persons and\nproperty while changing unduly burdensome or nonsensical requirements.\nExecutive Order 12866 states that \"Federal agencies should promulgate only such regulations as\nare required by law, are necessary to interpret the law, or are made necessary by compelling\nneed, such as material failures of private markets to protect or improve the health and safety of\nthe public, the environment, or the well-being of the American people ... .\" The mission of the\nPHMSA is to ensure the safety of the natural gas and hazardous liquids pipeline system.\nPipeline operators do not always bear the full costs of an incident. Even in cases where they\nprovide compensation for losses that can be monetized, those monetary penalties or settlements\ndo not necessarily capture the full impact on affected parties, especially when a death or injury\noccurs. As a result, there is a negative externality present in which the company may not take the\nfull societal cost of a possible incident into account in its decision-making. The negative\nexternality alters the company’s decision about safety precautions, leading to a need for\ngovernment to set minimum levels of safety precautions. Pipeline safety regulations are\ndesigned to address this potential market failure. The rulemaking package analyzed here is more\nspecifically intended to improve compliance with these regulations by updating references and\ntechnical standards, providing clarification, and removing conflicting language. Some of the\nprovisions also promote improved pipeline integrity and safety by addressing small gaps in the\ncurrent regulations, as discussed in more detail below.\n4\n\n<<<PAGE 5>>>\n\nFebruary 2015\nExecutive Orders 12866 and 13563 direct all Federal agencies to consider the costs and benefits\nof “significant regulatory actions.” Federal agencies are directed to develop a formal Regulatory\nImpact Analysis consistent with Office of Management and Budget (OMB) Circular A-4 for all\n“economically significant” rules, or those rules estimated to have an impact of $100 million in\n1995 dollars or more in any one year. The Order also requires a determination as to whether a\nrule could adversely affect the economy in terms of productivity and employment, the\nenvironment, public health, safety, or State, local, or tribal governments. This requirement\napplies to rulemakings that rescind or modify existing rules as well as to those that establish new\nrequirements. The goal of the analysis is to provide decision makers with a clear indication of the\nmost efficient alternative – that is, the alternative that generates the largest net benefits to society\nignoring distributional effects.\nThis rule has been considered a significant regulatory action under Section 3(f) of Executive\nOrder 12866 (58 FR 51735), and therefore is reviewed by OMB. This rule is significant under\nthe Regulatory Policies and Procedures of the Department of Transportation (44 FR 11034).\nThis rule falls below the $100 million per year in annual impact threshold. This regulatory\nanalysis:\n• Identifies the target problem, including a statement of the need for the action.\n• Identifies available alternative approaches\n• Defines the baseline.\n• Defines the scope and parameters of the analysis.\n• Defines and evaluates the costs and benefits of the action and the main alternatives\nidentified by the analysis.\n• Compares the costs and benefits.\n• Interprets the cost and benefit results.\nSubsections 3.1 to 3.12 describe the regulatory changes in detail and the specific needs to which\neach regulatory change responds.\n3.1 Responsibility to Conduct Construction Inspections\nThis rulemaking action would amend the Federal pipeline safety regulations §192.305 and\n§195.204. The amendments would specify that a transmission pipeline or main cannot be\ninspected by someone who performed the construction task requiring inspection.\nCurrently, PHMSA does not explicitly state that those who perform a construction task cannot\ninspect their own work. The National Association of Pipeline Safety Representatives (NAPSR)\nrecommended that contractors who install a transmission line or main should not be allowed to\ninspect their own work based on their experiences with poor quality construction by\nunsupervised contractors. Agreeing with NAPSR, PHMSA adopted the rule and took it a step\n5\n\n<<<PAGE 6>>>\n\nFebruary 2015\nfurther. PHMSA extended the prohibition to include non-contractor pipeline personnel and\nhazardous liquid lines. .\nPHMSA is not requiring that operators hire a third party to perform inspections and revised the\nlanguage to clarify who is excluded from the inspections. Taking into consideration discussions\nwith the Technical Advisory Committees (TACs), PHMSA adopted language that explicitly\nidentified the individual who performed the construction task as prohibited from carrying out the\nrequired inspection.\n3.2 Leak Surveys for Type B Gathering Lines\nThis rulemaking action would amend the Federal pipeline safety regulation §192.9 to include the\nperformance of leak surveys for Type B gathering lines by operators and to repair any leaks\ndiscovered.\nGathering lines are pipelines or parts of a connected series of pipelines that are used to transport\ngas from a production facility to the first processing plant. Type B is a risk category for lower\npressure lines with a MAOP hoop stress of less than 20 percent SMYS (specified minimum yield\nstrength).\n3\nCurrently, operators of onshore Type B gathering line have to comply with other design,\ninstallation, construction, and initial testing requirements for transmission lines, and corrosion\ncontrol requirements if of metallic construction. Additionally, operators already must include\nType B gathering lines in their damage prevention and public education programs, establish a\nMAOP following §192.619, and adhere to requirements for maintaining and installing line\nmarkers that apply to transmission lines.\nIn September 2006, NAPSR passed a resolution requesting regulatory change to Type B lines.\nMore specifically, the Supplemental Notice of Proposed Rule Making (SNPRM) [Docket No.\nRSPA-1998-4868; Notice 5] and the Final Rule for gathering lines [Federal Register; March 15,\n2006 (Volume 71, Number 50)] both identified the need to include leak surveys as a compliance\nactivity for Type B gathering lines. It was not incorporated in the Final Rule as it went beyond\nthe scope of the SNPRM and PHMSA did not want to further postpone the rulemaking.\nAnnual leak surveys are a common but not universal practice on Type B gathering lines. In\ncalendar year 2011, the annual Type B report data showed there were 289 leaks eliminated or\nrepaired by operators, with the leading cause of leaks being external corrosion. Ensuring that all\noperators perform regular leak surveys will help to detect additional gas leaks from pipelines\noperating under low pressures in a timely manner.\n3 PHMA’s definition of gathering lines can be found here:\nhttps://www.federalregister.gov/articles/2005/10/03/05-19455/gas-gathering-line-definition-alternative-\ndefinition-for-onshore-lines-and-proposed-safety-standards#h-14\n6\n\n<<<PAGE 7>>>\n\nFebruary 2015\n3.3 Qualifying Plastic Pipe Joiners\nThis rulemaking action would amend the Federal pipeline safety regulation §192.285(c) to\nprovide greater scheduling flexibility and stricter standards for re-qualification of persons who\nmake joints in plastic pipes.\nUnder the current §192.285(c) rule, a joiner must be re-qualified for a certain procedure if the\nperson did not perform that particular joint procedure or has three joints or three percent of\njoints, whichever is greater, found unacceptable within a 12-month time period. This\namendment will extend the 12-month time period to 15 months and reduce the number of\nunacceptable joints to just one. If any production joint is found unacceptable, a joiner is required\nto re-qualify.\nNAPSR in its petition (2008-03-AC-1) noted that the current rule setting a 12-month time period\nwas restrictive and caused the date to constantly be pushed to an earlier date each year.\nAdditionally, NAPSR noted there are a large number of operators requesting waivers similar to\nNAPSR stating current regulations set too low of standards for joiner re-qualification.\n3.4 Mill Hydrostatic Tests for Pipe to Operate at Alternative Maximum Allowable\nOperating Pressure (MAOP)\nThis rulemaking action would amend the Federal pipeline safety regulation §192.112 by\ndisallowing the combining of loading stresses imposed by pipe mill hydrostatic testing\nequipment for the mill test.\nEliminating the allowance of combining equipment loading stresses will increase the internal test\npressure for mill hydrostatic tests for new pipe to be operated at an alternative MAOP. The\nMAOP refers to the wall strength of a pipe. This requirement ensures new pipes will receive a\nmill test at a more accurate pressure level of at least 95 percent SMYS and therefore pipes will\nbe more correctly labeled before being put into operation.\nA hydrostatic mill test requires placing the pipe in a device that uses water to simulate pressure\nlevels. The current rule allows combining the loading stress exerted naturally by the mill test\ndevice as a part of the total pressure applied to the pipe. However, this leads to inaccuracies and\npotential mischaracterization of the actual strength of the pipe. PHMSA identified a number of\ncases throughout 2008 to 2010 where pipe did not meet the regulatory strength standards.\nOn May 21, 2009 PHMSA issued Advisory Bulletin “Pipeline Safety: Potential Low and\nVariable Yield and Tensile Strength and Chemical Composition Properties in High Strength Line\nPipe.” In this bulletin, PHMSA warned owners and operators of natural gas and hazardous liquid\npipeline systems that some pipe joints were found to have as much as 15 percent lower strength\nthan the values advertised by the pipe manufacturer. Following this statement, the Interstate\n7\n\n<<<PAGE 8>>>\n\nFebruary 2015\nNatural Gas Association of America (INGAA) conducted a study that suggested this change to\nthe testing calculation procedure as one way to prevent operators from putting mislabeled pipe\ninto the ground.4 This change would affect the minority of operators who function under 80\npercent SMYS.\n3.5 Regulating the Transportation of Ethanol by Pipeline\nThis rulemaking action would amend the Federal pipeline safety regulation §195.2 to add ethanol\nto PHMSA’s definition of “hazardous liquid.”\nPresently, a hazardous liquid is defined as petroleum, petroleum products, or anhydrous\nammonia. This definition would be expanded to include ethanol. With increasing demand for\nethanol, pipelines will be utilized more to transport it and therefore the necessary precautions\nmust be taken.\nA previous statement published in the Federal Register (72 FR 45002, Docket Number:\nPHMSA-2007-28136) on August 10, 2007 identified that ethanol “may pose unreasonable risk to\nlife or property,” according to the meaning found in 49 USC 60101(a) (4) (B), and therefore\nethanol, ethanol blends, and other biofuels constitute “hazardous liquids for purposes of the\npipeline safety laws and regulations.\n” From this statement, the few ethanol pipeline operators\nthat exist have already adopted hazardous liquid safety and reporting standards for the biofuel.\n3.6 Transportation of Pipe\nThis rulemaking action would amend the Federal pipeline safety regulation §192.65 to remove\nthe exemption of pipe transported before November 12, 1970, to adhere to API’s Recommended\nPractices 5L1.\nThe current rule states that operators may not install pipe with a hoop stress equal to or greater\nthan 20 percent and an outer diameter to wall thickness of 70 to 1 or more transported by rail,\nunless it obeys API’s Recommended Practices 5L1 or the pipe was transported prior to\nNovember 12, 1970. This exemption existed because the transportation of pipe stockpiled prior\nto that date cannot be verified under API standards.\nThis exception has now become almost obsolete. The Interstate Natural Gas Association of\nAmerica (INGAA) conducted surveys and found no pipe made transported before November 12,\n1970. NAPSR agreed that there is likely minimal stock of this vintage pipe.\nHowever, in the unlikely case that there is still vintage pipe, operators should not be allowed to\nuse it. As seen in the Enbridge pipeline incident on July 4, 2002 and as recommended by the\n4 The INGAA Foundation, “White Paper: Identification of Pipe with Low and Variable Mechanical Properties in High\nStrength, Low Alloy Steels,” September 2009.\n8\n\n<<<PAGE 9>>>\n\nFebruary 2015\nNational Transportation Safety Board (NTSB) report on the incident, all pipe transported by rail\nshould be subject to API’s Recommended Practice 5L1.5\n3.7 Offshore Pipeline Condition Reports\nThis rulemaking action would repeal the Federal pipeline safety regulations §191.27 and §195.57\nthat require operators to submit a report to PHMSA within 60 days of completing the underwater\ninspections of pipelines in the Gulf of Mexico required by §§ 192.612(a) and 195.413(a).\nSections 192.612(a) and 195.413(a) no longer require operators to perform underwater\ninspections of all pipelines in the Gulf, but rather only necessitate periodic, risk-based\ninspections of shallow-water pipelines. With the elimination of the underwater inspections, a 60-\nday reporting period becomes inconsistent with current regulations and therefore PHMSA\nrecommends their repeal.\n3.8 Calculating Pressure Reductions for Hazardous Liquid Pipeline Integrity Anomalies\nThis rulemaking action would amend the Federal pipeline safety regulation §195.452(h)(4)(i) to\ninclude an alternative method for calculating a pressure reduction for immediate repair\nconditions caused by issues other than corrosion.\nCurrently, an operator of a hazardous liquid pipeline must immediately repair the pipeline by\nreducing the operating pressure as determined by a formula provided in §451.6.2.2(b) of\nASME/ANSI B31.4. There are many threats that can cause an immediate repair condition, yet\nthe formula provided focuses only on corrosion and limits the scope of the rule.\nOn July 17, 2007, PHMSA’s Final Rule attempted to amend §195.452(h)(4)(i); however it was\nunable to be incorporated due to inaccurate amendatory instructions. This amendment corrected\nthose issues.\nThe new proposal considers the language suggested by the TACs and now states that to calculate\nthe reduction in pressure, the operator must reference 195.452(h)(4)(i)(B) or if that formula does\nnot apply, a 20 percent or greater reduction from the actual operating pressure should be\nimplemented until repairs are complete.\n3.9 Testing Components other than Pipe Installed in Low- Pressure Gas Pipelines\nThis rulemaking action would repeal the Federal pipeline safety regulation paragraph\n§192.505(d) that exempts certain components from post-installation strength test requirements in\n5 The Enbridge pipeline incident released approximately 6,000 barrels of crude oil due to fatigue cracks in the pipe\nin Cohasset, Minnesota. The NTSB report can be found here:\nhttp://www.ntsb.gov/doclib/reports/2004/PAR0401.pdf\n9\n\n<<<PAGE 10>>>\n\nFebruary 2015\nSubpart J of Part 152 and add that provision to §192.503, which imposes general rules applicable\nto testing all gas pipelines.\nThe GPTC wrote a letter dated March 25, 2010, petitioning PHMSA to repeal and add that\nprovision to the sections stated above.\n3.10 Alternative MAOP Notifications\nThis rulemaking action would amend the Federal pipeline safety regulation §192.620(c)(1) to\nrequire operators to give 60 days’ notice prior to the start of pipe manufacturing or construction\nactivities of new alternative MAOP pipelines.\nUnder current regulations, operators are required to give 180 days’ notice to each PHMSA\npipeline safety regional office where the pipeline is in service before using a new alternative\nMAOP on any segment. The change will be less restrictive for operators by shortening the\nnotice days to 60. The 60 days’ notice will not delay project activities for operators, while still\nallowing PHMSA enough forewarning to schedule personnel for safety inspections.\n3.11 National Pipeline Mapping System (NPMS)\nThis rulemaking action would amend the Federal pipeline safety regulation §191.29 and §195.61\nto implement the statutory requirement for the submission of NPMS data.\nPHMSA collects NPMS data annually since 2002 as outlined in Section 15 of the Pipeline Safety\nImprovement Act.\n6 Operators are required to submit geospatial, attribute, and metadata as well\nas public contact information and a transmittal letter. This rulemaking does not change the\nsubmission timeline or any requirements.\n3.12 Welders vs. Welding Operators\nThis rulemaking action would amend the Federal pipeline safety regulations §192.225, §192.227,\n§192.229, §195.214, §195.222 to include welding operators as qualified personnel of\nmechanized and automated welding equipment by adding Section 9 and Appendix A of API\n1104 as qualification references.\nIn the current regulation, welders are qualified under Section 6 of API 1104 or Section IX of the\nASME Boiler and Pressure Vessel Code. In expanding the qualification references and including\nwelding operators, PHMSA is ensuring knowledgeable personnel.\n6 https://www.npms.phmsa.dot.gov/Documents/Pipeline%20Safety%20Improvement%20Act%202002.pdf\n10\n\n<<<PAGE 11>>>\n\nFebruary 2015\n3.13 Components Fabricated by Welding\nThis action would amend the Federal pipeline safety regulation §192.153 to clarify the design\nand test requirements for pressure vessels in meter stations, compressor stations, and other\nlocations that are tested to Class 3 requirements to meet the 49 CFR Part 192 requirements and\nare tested at 1.5 times the MAOP.\nPresently, the rule does not explicitly state the testing requirements, but rather refers to them\nobliquely. This recommendation serves to clearly specify the requirements. Confusion arose\nfrom the ASME BPVC Section VIII test pressure standard of 1.3 times the MAOP. However,\nthis test factor does not apply to non- specially ordered compressors or meter stations, or Class 3\nor Class 4 locations and therefore is not in compliance with PHMSA regulations.\n3.14 Editorial Amendments\nIn this NPRM, PHMSA is also making the following editorial amendments to the Federal\npipeline safety regulations:\nIn §195.571, the NACE Standard on Cathodic Protection is now Incorporated by Reference.\nIn the §195.3(c) table indicating publications incorporated by reference, ANSI/API\nRecommended Practice 651 is corrected to show the right source and reference material\n§195.565 and §195.573(d).\nIn §195.2, the definition of “Alarm” is amended to include the codification of the new control\nroom management regulations (74 FR 63310).\nIn §192.925(b) and (b)(2), “indirect examination” is replaced with “indirect inspection” for\nconsistency with §192.925(a) and the relating NACE standard.\nIn §195.428(c), “§5.1.2” is revised to “§7.1.2” to correctly reference overfill protection\nrequirements for above ground tanks in the 2010 edition of API Standard 2510.\nIn §192.3, the definition of “Welder” and “Welding Operator” is added.\n4 Identification of Available Alternative Approaches\n4.1 No Action\nThis was used as the baseline against which PHMSA compared all other alternatives.\nRegulatory analyses typically consider an alternative in which the agency would not take any\naction, because it would maintain the status quo. No new requirements would be levied. No costs\nwould be incurred to implement new requirements. No new benefits would result.\n11\n\n<<<PAGE 12>>>\n\nFebruary 2015\nPHMSA has an obligation to ensure the safe and effective transportation of hazardous liquids\nand gases by pipeline. The changes in this rulemaking serve that purpose by clarifying the\npipeline safety regulations, eliminating conflicting provisions, responding to new statutory\nmandates, and eliminating unduly burdensome requirements. A failure to undertake these\nactions would allow for the continued imposition of unnecessary compliance costs without\nincreasing public safety. Accordingly, PHMSA rejected the “no action” alternative.\n4.2 Revisions\nThis alternative was determined by PHMSA as the preferred regulatory option and is compared\nin the document with the baseline “no action” alternative.\nPHMSA is proposing to make certain amendments, corrections, and editorial changes to the\npipeline safety regulations. These revisions would eliminate inconsistencies and respond to\nseveral petitions for rulemaking and recommendations from our stakeholders, thereby facilitating\nthe safe and effective transportation of hazardous liquids and gases by pipeline. The changes in\nthis rulemaking serve that purpose by clarifying the pipeline safety regulations and eliminating\nunduly burdensome requirements.\n5 Industry Information\nThe affected industry comprises owners and operators of regulated natural gas and hazardous\nliquid pipelines. These include a mix of large and small businesses, as well as publically owned\nutilities, municipalities, and other organizations. Using a combination of PHMSA 2011 Annual\nReport data and the Dun and Bradstreet company database, there are approximately 3,000\nregulated entities when all corporate subsidiaries are separately counted, with a total of 150,000\nonsite employees. There are wide variations across entities with respect to the share of\nemployees actually engaged in pipeline operations, especially for public agencies.\nAmong these entities, common industry (NAICS) codes are 211111, Crude Petroleum and\nNatural Gas Extraction; 221210, Natural Gas Distribution; 324110, Petroleum Refineries;\n486910, Pipeline Transportation of Refined Petroleum Products; 486210, Pipeline Transportation\nof Natural Gas; and 424720, Petroleum and Petroleum Products Merchant Wholesalers.\nMany of the specific provisions in this rulemaking would apply only to specific subsets of this\npopulation, such as operators of gas gathering lines, as described in more detail in Section 6\nbelow.\n12\n\n<<<PAGE 13>>>\n\nFebruary 2015\n6 Definition and Evaluation of the Benefits and Costs\n6.1 Data Sources and Limitations\nCost information is taken from PHMSA databases and external datasets as detailed more\nspecifically below. In many cases the changes are so small as to entail little to no\nquantifiable costs.\n6.2 Costs\nIn the sub-sections below, each provision of the rulemaking is analyzed individually for\npotential cost implications.\n6.2.1 Responsibility to Conduct Construction Inspections\nConstruction safety inspections are integral to ensuring the transmission line or main is correctly\nbuilt and assembled to minimize future hazards. With this provision, PHMSA is not requiring\noperating companies to hire a third party to perform the inspections, only clarifying that the same\nemployee who conducted the work cannot also inspect it. Inspections can be performed with\nother employees, but that employee must not have performed the task under inspection.\nCompliance costs for this provision are minimal, as it clarifies the existing inspection\nrequirement.\n6.2.2 Leak Surveys for Type B Gathering Lines\nThis section requires operators of Type B gathering lines to perform annual leak surveys for\nmore rapid detection of external corrosion. PHMSA performed a cost analysis by averaging the\ndaily rate of two leak survey service providers. The average daily cost of surveying two miles of\npipeline per day equaled $600. Averaging 2010, 2011, and 2012 miles of Type B gathering lines\nprovided an estimation of how many miles would need to be inspected annually. Approximately\n3,650 miles of Type B gathering lines will be required to be inspected annually. Multiplying that\nby the average cost of $300 per mile (i.e. $600 per 2 miles), the upper bound of total annual\nexpenditure is approximately $1.1 million.\nLeak surveys, while not currently required for Type B gathering lines, are a widespread industry\npractice because they serve a business purpose in helping to detect leaks, thereby reducing lost\ngas and liability exposure. Although operators do not submit data on the extent of these surveys,\nPHMSA believes that approximately half of all Type B gathering line mileage that would\notherwise be affected by this proposal is already being inspected. Therefore, a more realistic\nestimate of the actual incremental cost is approximately 50% of the upper bound of $1.1 million,\nor $0.55 million per year.\n13\n\n<<<PAGE 14>>>\n\nFebruary 2015\n6.2.3 Qualifying Plastic Pipe Joiners\nPHMSA’s proposal to extend the recertification period from 12 months to 15 months will result\nin a small cost savings for the affected group of joiners, since their requalification will come up\nslightly less frequently. At the same time, a small number of joiners will require requalification\nmore often because of the proposal to reduce the standard on unacceptable joints from three\njoints or three percent, whichever is greater, to just one joint. On balance, the overall cost\nimplications will be minimal, and the overall impact will be a cost savings for the majority of\njoiners.\n6.2.4 Mill Hydrostatic Tests for Pipe to Operate at Alternative Maximum Allowable\nOperation Pressure (MAOP)\nThis is a technical correction to a testing procedure to ensure that pipe can actually withstand the\noperating pressure at which it is rated. The removal of the allowance for equipment loading\nstresses is a change to the estimation formula and does not require new equipment or techniques.\nOf the small group of manufacturers who produce pipe intended for operation at 80 percent\nSMYS, many already test up to the 100 percent level, so this rulemaking will affect few\nfacilities. As this change is a technical correction to improve the accuracy of the labeled SMYS,\nthere are no significant costs.\n6.2.5 Regulating the Transportation of Ethanol by Pipeline\nThe few ethanol pipeline operators in existence already handle and report as if ethanol were a\nhazardous liquid due to a PHMSA policy statement from August 10, 2007 identifying the risks\ninvolved in ethanol transportation. The increasing demand and expansion of ethanol transported\nby pipe may pose significant future costs and revenue to the industry, yet this rulemaking does\nnot affect that. As a codification of an existing policy requirement, this section does not entail\nany significant changes in compliance costs.\n6.2.6 Transportation of Pipe\nAs studies performed by PHMSA and INGAA noted, there is relatively little, if any, vintage pipe\nin stock. Vintage pipe refers to pipe transported prior to November 12, 1970. The exception for\nallowing the installation of vintage pipe not transported under API’s Recommended Practices\n5L1 is outdated and therefore this rule serves primarily as a reporting clarification and updating\nof regulations. There are no expected cost impacts.\n6.2.7 Offshore Pipeline Condition Reports\nUnder this revision, operators no longer are required to provide a report 60 days after an\nunderwater pipeline inspection in the Gulf of Mexico. This editorial clarification maintains\n14\n\n<<<PAGE 15>>>\n\nFebruary 2015\nconsistency with other rules that are no longer observed. This section entails no net societal\ncosts or benefits.\n6.2.8 Calculating Pressure Reductions for Hazardous Liquid Pipeline Integrity Anomalies\nThis rule was already addressed in a previous rulemaking from July 17, 2007. With the\namendatory instructions corrected, this minor addition to calculating pressure reductions for a\npipe under immediate repair conditions will not result in any significant changes in compliance\ncosts.\n6.2.9 Testing Components other than Pipe Installed in Low- Pressure Gas Pipelines\nIn moving section 192.505 (d) to section 192.503, all post-installation strength test requirements\nare located in the same place within the regulations. As no requirements are changing, this\nrulemaking does not have any incremental compliance costs.\n6.2.10 Alternative MAOP Notifications\nThis rulemaking allows for a less restrictive notice period for operators who want to begin\nmanufacturing or construction activities with pipe of a new alternative MAOP: 60 days instead\nof the current 180 days. As such, it may yield small cost savings and additional flexibility for\noperators. PHMSA does not anticipate that this change will result in additional costs for the\nagency.\n6.2.11 National Pipeline Mapping System (NPMS)\nThis section simply incorporates existing statute-imposed requirements into the Pipeline Safety\nRegulations. Since 2002, operators have adhered to the same requirements that will now be\ncodified. There are no anticipated changes to operator filings or requirements, and accordingly\nno incremental compliance costs.\n6.2.12 Welders vs. Welding Operators\nThe additional qualifications for welders and welding operators under the new rulemaking\nprovide no more than a clarification of qualification references allowed by PHMSA. While this\nwill ensure qualified personnel are performing welding activities, it does not result in substantial\ncosts or benefits as the qualification was already outlined in API 1104 Section 9 and Appendix\nA.\n6.2.13 Components Fabricated by Welding\nAlthough comments expressed concern over additional costs for operators, this rule is a\nclarification of an existing rule found in 49 CFR §192.153(e) and distinguishes it from the other\nASME BPVC Section VIII ruling. The industry should already follow this requirement, even if\n15\n\n<<<PAGE 16>>>\n\nFebruary 2015\nit may have been misunderstood by some operators. This clarification of compliance does not\nincur any new costs to operators as 1.5 times MAOP is an industry standard already adopted by\nPHMSA.\n6.2.14 Editorial Amendments\nThe editorial adjustments correct errors, uphold consistency, and fix small discrepancies\nthroughout the Final Rule. There are no substantive changes to the requirements and therefore\nno supplementary compliance costs.\n6.2.15 Cost Summary\nIn general, many of these amendments are minor rulemakings with little or no substantive\nchanges to industry standards or compliance costs. Only one provision came with major\nquantifiable costs and this is estimated at $0.6 to million per year for additional operators to\nperform leak surveys for Type B gathering lines.\n6.3 Benefits\nPipeline incidents can result in death, injury, property damage, and environmental damage. The\nbenefits of the regulatory changes stem primarily from improvements to regulatory clarity and\nfrom upgraded safety requirements that are intended to reduce the number of pipeline incidents\nand their severity.\nEstimates of avoided incident costs are calculated using information on fatalities, injuries, and\nproperty damage (including lost product). Fatalities and injuries are converted to dollar terms\nusing values from departmental guidance documents, $9.1 million per fatality and $955,500 for\nan injury.7 [Based on departmental guidance, the injury and fatality figures rise 1.07% per year\nto account for wage increases over time.]\nIn the sub-sections below, the expected benefits of each provision of the rulemaking are analyzed\nindividually.\n6.3.1 Responsibility to Conduct Construction Inspections\nThis section is a clarification explicitly prohibiting the person(s) who performed a construction\ntask from inspecting their own work. Although this was already a widespread industry standard,\nthere may be some incremental safety benefits from formalizing this requirement.\n7 Trottenberg, Polly and Robert Rivkin. “Guidance on Treatment of the Economic Value of a Statistical Life (VSL) in\nU.S. Department of Transportation Analyses.” February 28, 2013. The injury number is equivalent to a “serious”\ninjury on the Abbreviated Injury Scale and is 10.5% of the VSL.\n16\n\n<<<PAGE 17>>>\n\nFebruary 2015\nBetween 1993 and 2012 there were 25 construction, installation, and fabrication- related\nincidents that resulted in $16,681,026 in reported property damage from gas transmission lines\nplus 47 incidents from hazardous liquid transmission causing $9,192,653 in property damage.\n8\nThe proportion attributable to errors caused by self-inspection is unknown, so benefits cannot be\nquantified for this provision. However, PHMSA believes that this explicit inspection rule will\nimprove safety by ensuring unbiased inspections.\n6.3.2 Leak Surveys for Type B Gathering Lines\nBy performing leak surveys annually, operators are more likely to detect leaks early, thereby\navoiding costlier future repairs and reducing the amount of gas lost. As mentioned in section\n3.2, during calendar year 2011, there were 289 reported leaks on Type B gathering lines\neliminated or repaired, with the lead cause of these leaks being external corrosion. Leak surveys\nare particularly important for low pressure gas gathering lines because these lines tend to leak\nrather than rupture. In addition to the direct operational benefits, annual leak surveys will also\nreduce the environmental harm caused by lost gas (i.e., the greenhouse gas potential of methane\nreleased into the atmosphere).\nAccording to PHMSA incident data collected from 1993 to 2012, external corrosion in gas\ngathering lines caused $2,277,870 in property damage and resulted in one injury.9 Other types of\nincidents, such as certain equipment failures and punctures, are also potentially preventable\nthrough leak surveys. Prior to 2010, the data unfortunately does not distinguish between Type A\nand Type B gathering lines. For the more limited period from 2010 to 2012, PHMSA incident\ndata includes one incident with an onshore type B gathering line that incurred $76,567 of\nproperty damage. This represents an annual average of $25,222 in safety benefits from incidents\non Type B gathering lines that are potentially preventable via annual leak surveys. There are\nalso environmental and climate-change benefits from reducing lost gas, but these could not be\nquantified because of limited data on the quantity of gas lost in the relevant incidents. In\naddition, these surveys would future cost savings for operators in terms of avoiding more costly\nrepairs. Operator leak reporting also gives PHMSA valuable information that can be used in\ntrending analysis for the determination of problem materials or poor operating practices. These\nimportant benefits cannot be quantified.\n8 http://primis.phmsa.dot.gov","truncated":true,"body_characters":53113}