{"operation":"document","citation":"0900006481a47e78","title":"Final Regulatory Impact Analysis for Pipeline Safety:  Integrity Management Program for Gas Pipelines RIN 2137-AE15","source_type":"rulemaking","agency":"Pipeline and Hazardous Materials Safety Administration","status":"current","official":true,"published_on":null,"effective_on":null,"summary":"Material conclusions and scope (quoted exactly): the rule adds a new Subpart P to 49 CFR Part 192 requiring gas distribution Integrity Management plans and EFV installation on new/replaced single-residence service lines (see passages regulations-gov-attachment-0900006481a47e78-node-3, -6, -16). PHMSA estimated the rule's present-value net benefits over 50 years to lie between $21 million and about $1.6 billion (passage node-3). The Agency assessed annual costs at about $130 million in the first year and about $101 million in subsequent years, with estimated annual monetary benefits between $111 million and $165 million (passage node-3). PHMSA estimated approximately 9,090 small entities would be impacted and that 9,343 operators, 1,138,000 miles of distribution mains and 60,970,000 services are affected (passages node-4, node-18, node-19). The RIA describes PHMSA's selection of a risk‑b^","machine_formats":{"json":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006481a47e78.json","markdown":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006481a47e78.md"},"app_url":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006481a47e78","source_url":"https://downloads.regulations.gov/PHMSA-2011-0009-0026/attachment_1.pdf","body":"<<<PAGE 1>>>\n\nFinal BEPTOf|/,pRWION\n9 -I A p- n ~> .\nRegulatory Impact Analysis: Final Rule\nPipeline Safety: Integrity Management Program for Gas Distribution\nPipelines\nPHMSA-RSPA-2004-19854\nOffice of Pipeline Safety\nPipeline and Hazardous Materials Safety Administration (PHMSA)\nU.S. Department of Transportation\nOctober 29,2009\n\n<<<PAGE 2>>>\n\nTABLE OF CONTENTS\nEXECUTIVE SUMMARY 1\n1. INTRODUCTION 3\n2. BACKGROUND 7\n3. REGULATORY ANALYSIS 8\n4. IDENTIFICATION OF THE PROBLEM AND THE NEED FOR THE RULE 8\n5. IDENTIFICATION OF AVAILABLE ALTERNATIVE APPROACHES 10\n6. INDUSTRY INFORMATION 15\n7. DEFINITION AND EVALUATION OF THE BENEFITS AND COSTS 17\n8. BREAK-EVEN ANALYSIS 61\n9. SUMMARY AND CONCLUSIONS 62\nAPPENDIX A: SUPPLEMENTARY STATISTICAL VALUE OF LIFE ANALYSIS 64\nAPPENDIX B: ESTIMATES OF AVERAGE COST PER LIFE SAVED 66\n11\n\n<<<PAGE 3>>>\n\nEXECUTIVE SUMMARY\nThe Pipeline and Hazardous Materials Safety Administration (PHMSA) is amending the\nFederal Pipelme Safety Regulations to require operators of gas distribution pipelines to\ndevelop and implement Integrity Management (IM) programs. The purpose of these\nprograms is to enhance safety by identifying and reducing pipeline integrity risks. The\nrule addresses the statutory mandates and recommendations from the Department of\nTransportation's (DOT) Office of the Inspector General (OIG) and stakeholder groups.\nThe IM programs required by this rule are similar to those required for gas transmission\npipelines but are tailored to reflect the differences in and among distribution pipelines.\nPHMSA requires operators of gas distribution pipelines to develop and implement IM\nplans that will better assure the integrity of their pipeline systems.\nAll E M program requirements pertain to distribution operators with the exception of\nmaster meter and small liquid petroleum gas (LPG) distribution systems. To minimize\nregulatory burdens, the rule establishes simpler requkements for master meter and LPG\noperators serving fewer than 100 customers from a single source, reflecting the relatively\nlower risk posed by these small pipeline systems.\nThe Regulatory Impact Analysis (RIA) finds that the rule is not expected to adversely\naffect the economy or the environment. The analysis fmds that, for those costs and\nbenefits that can be quantified, the present value of net benefits is expected to be between\n$21 million and about $1.6 billion over a 50-year period after all of the requirements are\nimplemented. Furthermore, the net benefits of the rule are expected to be positive if the\nrule results in eliminatmg only approximately 12.2 percent of the overall societal costs\nthe first year, and about 9.5 percent in subsequent years.\nPRESENT VALUE OF BENEFITS, COSTS, and NET BENEFITS OF THE RULE\nCALCULATED OVER 50 YEARS\n($ Millions)\nDiscouiilRate\n3%\n7%\nBenefits s\n2,942 to 4,373\n1,639 to 2,437\nCdM\n2,783\n1,618\nNet Benefits\n159 to 1,590\n21 to 719\nThe estimated monetary cost of the rule is $130 million in the first year and about $101\nmillion in subsequent years, while the estimated annual monetary benefits are between\n$111 million and $165 million. DOT has classified this rulemaking as an economically\nsignificant regulatory action under Section 3(f)(1) of Executive Order 12866, and a\nsignificant regulatory action under the DOT's regulatory policies and procedures (44 FR\n11034). There is substantial congressional, industry, and public interest in the rule.\nPHMSA has also estimated, as required by the Regulatory Flexibility Act (RFA), that the\nrule would have an impact on many small operators. PHMSA estimates that\n\n<<<PAGE 4>>>\n\napproximately 9,090 small entities will be impacted by the rule. PHMSA cannot estimate\nthe percent of revenues the costs of the rule represent for small operators, since the\nAgency does not have information on their revenues. The rule could result in a significant\nadverse economic impact for at least some of the small master meter and small LPG\nsystems, if the costs exceed 1 percent of their revenues. A Final Regulatory Flexibility\nAnalysis (FRFA), which discusses these issues has been completed and placed in the\ndocket.\nPHMSA determined that the rule would not impose annual expenditures on State, local,\nor tribal governments or the private sector in excess of $141.3 million, and thus does not\nrequire an Unfunded Mandates Act analysis.\n\n<<<PAGE 5>>>\n\n1. INTRODUCTION\nThe Pipelme and Hazardous Materials Safety Administration (PHMSA) has issued\nIntegrity Management Program (IM program) regulations for operators of hazardous\nliquid pipelines (49 CFR 195) and gas transmission pipelines (49 CFR Part 192). Those\nregulations require operators to continually assess, evaluate, repair, and validate through\ncomprehensive analysis the integrity of pipeline segments, and to take actions to address\napplicable threats and integrity concerns. Similar regulations do not currently exist for\ngas distribution pipelines.\nPHMSA is revising the Pipeline Safety Regulations to require operators of gas\ndistribution pipelines to develop and implement programs that will better assure the\nintegrity of their pipeline systems. PHMSA published a Notice of Proposed Rulemaking\n(NPRM) on June 25, 2008 (73 FR 36015), which proposed to extend its mtegrity\nmanagement approach to the largest segment of the Nation's pipeline network—the gas\ndistribution pipelines that directly serve homes, schools, businesses, and other natural gas\nconsumers. Significant differences between distribution pipelines and gas transmission\nor hazardous liquid pipelines made it impossible simply to apply the existing regulations\nto distribution pipelines. The proposed rule incorporated the same basic principles as\ncurrent integrity management regulations but with a slightly different approach to\naccommodate those differences.\nOver the period 1989-2008, significant incidents associated with gas distribution pipeline\nsystems result, on average, in more than 15 fatalities, over 62 serious injuries, and tens of\nmillions of dollars of property damages annually.' The purpose of this regulation is to\naddress the hazards that lead to those incidents as well as reduce gas loss by including\nleak management and excess flow valve (EFV) provisions.\nThis rule addresses recommendations from DOT's Inspector General and the National\nTransportation Safety Board (NTSB). It also implements requirements in the Pipeline\nInspection, Protection, Enforcement and Safety Act (PIPES Act) of 2006.\n1.1 Requirements of the Integrity Management Program\nThe requirements for distribution pipeline operators are described below.\nGas Distribution Pipeline Integrity Management (DIMP)\nThe final rule revises 49 CFR Part 192 to add integrity management requhements\napplicable to distribution pipelines. This addresses statutory mandates and builds on\nprevious similar requirements established for gas transmission pipelines. The final rule\n' Natural Gas Distribution: Significant Incidents Summary Statistics: 1989-2008, Significant Pipeline\nIncidents, PHMSA.\n\n<<<PAGE 6>>>\n\nalso adds a requkement that operators install excess flow valves (EFV) on all new and\nreplaced residential service lines serving single residences, as required by the PIPES Act.\nThe requirements for gas distribution operators and LPG operators with distribution\nsystems serving 100 or more customers from a single source (\"large\" LPG operators^) are\nlisted under section 1.1.1 below. These are followed by the requirements for master\nmeter operators and small LPG operators.\nL l . l Requirements for Gas Distribution Pipeline Operators and Large LPG\nOperators\nDistribution pipeline operators are required to implement an IM program similar to those\nrequired for gas transmission pipelines.\nPHMSA is adding a new Subpart P - Gas Distribution Pipeline Integrity Management to\n49 U.S.C, Part 192 as follows:\n§ 192.1001 What definitions apply to this subpart?\n§ 192.1003 What do the regulations in this subpart cover?\n§ 192.1005 What must a gas distribution operator (other than a master meter or small\nLPG operator) do to implement this subpart?\n§ 192.1007 What are the requked elements of an integrity management IM plan?\n§ 192.1009 What must an operator report when compression couplings fail?\n§ 192.1011 What records must an operator keep?\n§ 192.1013 When may an operator deviate from required periodic inspections under this\npart?\n§ 192.1015 What must a master meter or small liquefied petroleum gas (LPG) operator\ndo to implement this subpart?\nPHMSA is also revising section 192.383, Excess flow valve customer notification. The\nrevised section will be titled \"Excess flow valve installation,\" will eliminate the current\nrequirement for operators to notify customers of the availability of EFVs, and will requke\nEFVs to be installed on new and replaced service lines serving single family residences.\nElements of an IM Plan\nA gas distribution operator must develop and implement an integrity management\nprogram that includes a written integrity management plan as specified in § 192.1007.\nAn integrity management program is an overall approach by an operator to ensure the\nintegrity of its gas distribution system. An integrity management plan is a written\nexplanation of the mechanisms or procedures the operator will use to implement its\nintegrity management program and to ensure compliance with the new subpart P. These\noperators must also comply with sections 192.1009 through 192.1013.\n^ The term \"large\" is used solely to differentiate these operators from the \"small\" LPG operators referred to\nin the rule. Both \"large\" and \"small\" LPG operators are small entities for the purposes of the Regulatory\nFlexibility Analysis.\n\n<<<PAGE 7>>>\n\nThe IM Plan must address:\n(a) Knowledge. An operator must demonstrate an understanding of its gas distribution\nsystem developed from reasonably available information.\n(1) Identify the characteristics of the pipeline's design and operations and the\nenvironmental factors that are necessary to assess the applicable threats and\nrisks to its gas distribution pipeline.\n(2) Consider the information gained from past design, operations, and\nmaintenance.\n(3) Identify additional information needed and provide a plan for gaining that\ninformation over time through normal activities conducted on the pipeline (for\nexample, design, construction, operations or maintenance activities).\n(4) Develop and implement a process by which the IM program will be reviewed\nperiodically and refined and improved as needed.\n(5) Provide for the capture and retention of data on any new pipeline installed.\nThe data must include, at a minimum, the location where the new pipeline is\ninstalled and the material of which it is constructed.\n(b) Identifv threats. The operator must consider the following categories of threats to\neach gas distribution pipeline: corrosion, natural forces, excavation damage, other outside\nforce damage, material, weld or joint failure (including mechanical couplings),\nequipment failure, incorrect operation, and other concerns that could threaten the\nintegrity of its pipeline. An operator must consider reasonably available information to\nidentify existmg and potential threats. Sources of data may include, but are not limited\nto, incident and leak history, corrosion control records, continuing surveillance records,\npatrolling records, maintenance history, and excavation damage experience.\n(c) Evaluate and rank risk. An operator must evaluate the risks associated with its\ndistribution pipeline. In this evaluation, the operator must determine the relative\nimportance of each threat and estimate and rank the risks posed to its pipeline. This\nevaluation must consider each applicable current and potential threat, the likelihood of\nfailure associated with each threat, and the potential consequences of such a failure. An\noperator may subdivide its pipeline into regions with similar characteristics (e.g.,\ncontiguous areas within a distribution pipeline consisting of mains, services and other\nappurtenances; areas with common materials or environmental factors), and for which\nsimilar actions likely would be effective in reducing risk.\n(d) Identifv and implement measures to address risks. Determine and implement\nmeasures designed to reduce the risks from failure of its gas distribution pipeline. These\nmeasures must include an effective leak management program (unless all leaks are\nrepaired when found).\n(e) Measure performance, monitor results, and evaluate effectiveness.\n(1) Develop and monitor performance measures from an established baseline to\nevaluate the effectiveness of its IM program. An operator must consider the\n\n<<<PAGE 8>>>\n\nresults of its performance monitoring in periodically re-evaluating the threats\nand risks. These performance measures must include the following:\n(i) Number of hazardous leaks either eliminated or repaired as\nrequired by § 192.703(c) of this subchapter (or total number of\nleaks if all leaks are repaired when found), categorized by cause;\n(ii) Number of excavation damages;\n(iii) Number of excavation tickets (receipt of information by the\nunderground facility operator from the notification center);\n(iv) Total number of leaks either eliminated or repaired, categorized by\ncause;\n(v) Number of hazardous leaks either eliminated or repaired as\nrequired by § 192.703(c) (or total number of leaks if all leaks are\nrepaired when found), categorized by material; and\n(vi) Any additional measures the operator determines are needed to\nevaluate the effectiveness of the operator's IM program in\ncontrolling each identified threat.\n(f) Periodic Evaluation and Improvement. An operator must re-evaluate threats and risks\non its entire pipeline and consider the relevance of threats in one location to other areas.\nEach operator must determine the appropriate period for conducting complete program\nevaluations based on the complexity of its system and changes in factors affecting the\nrisk of failure. An operator must conduct a complete program reevaluation at least every\nfive years. The operator must consider the results of the performance monitoring in these\nevaluations.\n(g) Report results. Report, on an annual basis, the four measures listed in paragraphs\n(e)(l)(i)-(e)(l)(iv) of this section, as part of the annual report required by § 191.11. An\noperator also must report the four measures to the State pipeline safety authority if a State\nexercises jurisdiction over the operator's pipeline.\n1.1.2 Requirements for Master Meter Operators and Small LPG Operators\nMost master meter operators are small entities and operating their gas distribution\npipelines is not their principal occupation. These operators typically have limited on-\nstaff technical pipeline expertise. These operators have historically been treated\ndifferently withm Part 192. In particular, they have been subject to more limited\ndocumentation requirements. For example, master meter operators and small LPG\noperators are not required to submit annual reports.\nSection 192.1015 prescribes IM requirements applicable to these smaller operators. The\nmajor elements that these operators are required to include in their IM plans are the same\nas those in § 192.1007 applicable to other operators. The details of the elements are\nsimplified somewhat, to reflect both the relative simplicity of these pipelines and the\nlimited capability of the operators. For example, the required knowledge of their pipeline\nis focused on the approximate location and material of which it is constructed and\nrequired documentation of this knowledge is limited to documents showing the location\n\n<<<PAGE 9>>>\n\nand material of piping and appurtenances that are installed after the effective date of their\nIM programs and, to the extent known, in existence when the program becomes effective.\nThese operators are not required to submit performance measures, which is consistent\nwith their prior treatment with respect to annual reports. PHMSA is developing guidance\nsuitable for use by master meter and small LPG operators to develop simple IM plans for\ntheir pipelines. This guidance will be made available via PHMSA's web site after this\nfinal rule is published.\nThe remainder of this report examines the benefits and costs of the regulatory changes are\nexamined, as required by Executive Order 12866 and the Unfunded Mandates Reform\nAct. The final Regulatory Flexibility Analysis is filed separately in the docket.\n2. BACKGROUND\nThe Nation's existing pipeline infrastructure, much of which is over 50 years old,\nrequires regular safety and environmental reviews to ensure its reliability and integrity.\nTo improve safety, PHMSA established Integrity Management requirements in years\n2000 and 2002, for operators of hazardous liquid pipelmes (49 CFR 195.452).\nSubsequently, PHMSA issued E M program regulations for gas transmission pipelines in\nDecember 2003 (49 CFR Part 192, Subpart O). Both the hazardous liquid and gas\ntransmission pipeline IM program regulations require operators to analyze risks and focus\nincreased attention on safety, especially the portions of their pipeline that pose the highest\nrisk. This increased attention must include physical inspection (assessment) of the pipe\nusing in-line inspection, pressure testing, or direct assessment, remediation of anomalous\nconditions following the assessment, continual evaluation of the pipeline, application of\nadditional preventive and mitigative measures, and development of performance\nmeasures.\nCurrent IM program regulations, however, do not apply to gas distribution pipelines. Gas\ndistribution pipelines deliver gas to residences and other end users and are different from\nhazardous liquid and gas transmission pipelines.\nDistribution systems are composed of a grid of \"mains\" and \"service lines.\" A main is a\npipeline that serves as a common source of supply for multiple customers, often located\nunder municipal streets that may be in heavily populated or congested areas. Service\nlines transport gas from the mains to the meters or customer-owned piping of residential,\ncommercial, and industrial customers. Distribution pipelines can measure as large as 36\ninches in diameter; however, most are much smaller, ranging in size from one-half inch\nservice lines to 8 inches in diameter for some mains. These pipelines generally operate at\nlower pressures than the transmission pipelines and are owned and operated by local\ndistribution companies. Distribution pipelines are constructed of a variety of materials,\nboth metallic and non-metallic. Approximately half of the pipe in distribution systems is\nplastic. To reach the many end users they serve, distribution pipelines include extensive\nbranching and interconnection, which is significantly different from the long,\nuninterrupted runs of transmission system pipe. These differences make it impractical to\n\n<<<PAGE 10>>>\n\nsimply apply gas transmission integrity management requirements to distribution\npipelines and instead necessitate integrity management program requirements tailored to\ndistribution pipelines.\n3. REGULATORY ANALYSIS\nExecutive Order 12866 dhects all Federal agencies to consider the costs and benefits of\n\"significant regulatory actions.\" Federal agencies are directed to develop a formal\nRegulatory Impact Analysis consistent with Office of Management and Budget (OMB)\nCircular A-4 for all \"economically significant\" rules, or those rules estimated to have an\nimpact of $100 million or more in any one year. The Order also requires a determmation\nas to whether a rule could adversely affect the economy in terms of productivity and\nemployment, the environment, public health, safety, or State, local or tribal governments.\nThis requirement applies to rulemakings that rescind or modify existing rules as well as\nto those that establish new requirements. The goal of the analysis is to provide decision\nmakers with a clear indication of the most efficient alternative—that is, the alternative\nthat generates the largest net benefits to society (ignoring distributional effects).\nThis regulatory analysis:\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\nalternatives identified by the analysis.\n• Compares the costs and benefits.\n• Interprets the cost and benefit results.\n4. IDENTIFICATION OF THE PROBLEM AND THE NEED FOR THE RULE\nAlthough the gas distribution industry is subject to rate regulation, and the regulators act\nto reflect forces that otherwise would come from the market, the pipeline infrastructure is\ninstalled so that the local operator that delivers that product has somewhat of a natural\nmonopoly. Research on this specific industry has indicated that there are no robust\nmarket signals or incentives to prompt operators to thoroughly assess the condition of\ntheir pipelines or to implement integrity management programs. For example, the\nGovernment Accountability Office (GAO) has pointed out in a, study of gas transmission\noperators'* that the gas transmission integrity management program prompted some\n' See: http://www.naturaigas.org/business/industrv.asp:\nhttp://www.naturalgas.org/naturalgas/distribution.asp: Fred Foldvary, The Progress Report.\nhttp://www.progress.org/fold74.htm.\n• * GAO, Gas Pipeline Safety, Preliminary Observations on the Integrity Management Program and 7-Year\nReassessment Requirement, GOO-06-474T, Testimony Before the Subcommittee on Highways, Transit\nand Pipelines, Committee on Transportation and Infrastructure, U.S. House of Representatives. Statement\n\n<<<PAGE 11>>>\n\noperators to make assessments of their pipelines for the first time. The market structure\nof the distribution industry may have led to distribution system operators spending less\nthan the socially optimal amount of resources and attention to pipeline integrity.\nOperators may also have inadequate information to assess the risks associated with gas\ndistribution systems, because they may not have observed incidents involving death or\nserious injury in any given year (or decade, for that matter), and smaller operators are\neven less likely to see such incidents. Even though an incident in a particular pipeline is\na low probability event, the risk is still inherent in the system itself, and consequences of\nan incident can be severe. Therefore, the aggregate safety impacts on a national basis\njustify more significant investment in risk management systems.\nRecognizing these problems, PIPES Act mandates integrity management programs for\ndistribution systems. Given this statutory mandate, the rest of this analysis seeks to\nidentify the most efficient approach to integrity management. PHMSA considered other\nmeans of dealing with the problem before proposing new, comprehensive requirements.\nPHMSA has examined the feasibility of regulating at the State level. Currently gas\npipeline operators are subject to differing State regulations. PHMSA has determined that\nthe diversity in State-specific regulations dictates the need for Federal regulatory\noversight. Each State's program must be certified, or subject to an agreement with\nPHMSA to act on its behalf, as a condition for Federal funding.\nPHMSA has concluded that a better understanding on the part of operators of the risks\nposed by their pipeline systems, and a better focus of their actions to address the most\nsignificant of those risks is the most effective way to improve the Nation's already-\ncommendable pipeline safety record. Consequently, PHMSA has been implementing\nintegrity management requirements on various pipeline types as part of its program to\nimprove pipeline safety. The historical record shows, however, that more adverse safety\nconsequences result from accidents on distribution pipelines than from those on the\npipelines already subject to IM program requirements. Based on PHMSA data from 2001\nthrough 2008, 75 percent to 80 percent of all deaths and injuries occur on gas distribution\nsystems. PHMSA data show that 11 percent of the incidents across all pipeline systems\ninvolve deaths or injuries, while the percentage for gas distribution pipelines during the\nsame period is 24 percent and for transmission pipelines it is 3 percent. It is not possible\nto produce a significant improvement in pipeline safety without addressing distribution\npipelines. Therefore, PHMSA has concluded that it is appropriate to establish IM\nprogram requirements that will foster a similar understanding of and focus on risk among\ndistribution pipeline operators.\nIn 2004, the DOT Inspector General (IG) pointed out that recent accident trends for gas\ndistribution pipelines were unfavorable and suggested the application of integrity\nmanagement principles could help improve the safety of distribution pipelines. The IG\nacknowledged that the reason distribution pipeline operators were exempt from the\nof Katherine Siggerud, Du-ector, Physical Infrastructure Issues, March 16, 2006. See:\nhttp://www.gao.gov/new.items/d06474t.pdf.\n\n<<<PAGE 12>>>\n\nregulations was that distribution pipelines could not use the same inspection methods\nused for hazardous and transmission pipelines. Nevertheless, the IG concluded that there\nwas no reason other elements of integrity management could not be implemented for\ndistribution pipelines.\nThe IG recommended to Congress^ that DOT define an approach for requiring operators\nof distribution pipeline systems to implement some form of integrity management or\nenhanced safety program with elements similar to those required in hazardous liquid and\ntransmission pipeline IM plans. The Appropriations Committee then asked PHMSA \"to\nreport to the House and Senate Committees on Appropriations by May 1, 2005, detailing\nthe extent to which integrity management program elements may be applied to the natural\ngas distribution pipeline industry in order to enhance distribution system safety.\"^\nPHMSA submitted the report \"Assuring the Integrity of Gas Distribution Pipeline\nSystems\" to Congress in JUne 2(X)5, describing the program used to identify opportunities\nfor improving the safety oi^ distribution pipeline systems.\nPHMSA developed the program in two phases. Phase 1 identified the nature of\nrequirements that might be imposed and any additional guidance or consensus standards\nthat might be needed to assist operators in implementing any integrity management\nrequirements. Phase 2 included development of appropriate requirements by PHMSA\nand preparation of guidance/standards by appropriate bodies. During the development of\nPhase 1, PHMSA involved a large number of key stakeholder groups including State and\nFederal regulators, representatives from the spectrum of distribution operators, interested\nmembers of the public, and representatives of the Nation's fire service. The stakeholders\nagreed with the DOT IG and Congress's recommendations and concluded that it would\nbe appropriate to modify the regulations to include a risk-based integrity management\nprocess for gas distribution pipelines.\n5. IDENTIFICATION OF AVAILABLE ALTERNATIVE APPROACHES\nPHMSA considered several alternatives to assure the necessary protection from potential\nincidents caused by gas distribution pipelines, with the intention of selecting the\nalternative that is likely to result in the highest net benefits. PHMSA considered the\nfollowing approaches:\n• Apply existing gas transmission pipeline IM program regulations to gas\ndistribution pipelines.\n• Model State legislation potentially imposing requirements on excavators and\nothers outside the regulatory jurisdiction of pipeline safety authorities.\n' \"Progress and Challenges in Improving Pipeline Safety,\" Statement of the Honorable Kenneth M. Mead,\nInspector General, Department of Transportation, before the Committee on Energy and Commerce,\nSubcommittee on Energy and Air Quality, U.S. House of Representatives, July 20, 2004.\n* House of Representatives report 108-792, November 20, 2004.\n^ \"Integrity Management for Gas Distribution, Report of Phase 1 Investigations,\" prepared by Joint\nWork/Study Groups, December 2005, U.S. DOT/PHMSA - Report: DIMP Phase 1, Doc. Number: RSPA-\n2004-19854-70, available at http://dmses.dot.gov/docimages/p84/388302.pdf.\n10\n\n<<<PAGE 13>>>\n\n• Develop guidance documents for adoption by States.\n• Implement prescriptive Federal regulations, specifying in detail, actions that must\nbe taken to assure distribution pipeline integrity.\n• Implement risk-based, flexible, performance-oriented Federal regulations,\nestablishing high-level elements that must be included in integrity management\nprograms.\nAfter considering all the alternatives, PHMSA selected the following alternative:\nimplementation of risk-based, flexible, performance-oriented Federal regulations\nestablishing high-level elements that must be included in integrity management\nprograms.\n5.1 Baseline: 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\nany action, because it would maintain the status quo. No new requirements would be\nlevied. No costs would be incurred to implement new requirements. No new benefits\nwould result.\nIn response to the mandate concerning IM programs for distribution systems contained in\nThe Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (Public Law\nNo: 109-468, Dec. 29, 2006), also known as the PIPES Act, PHMSA is initiating this\nrulemaking. PHMSA is extending its mtegrity management approach to the largest\nsegment of the Nation's pipeline network—the distribution systems that directly serve\nhomes, schools, businesses, and other natural gas consumers. Begiiming in 2000, the\nAgency promulgated regulations requiring operators of hazardous liquid pipelines (49\nCFR 195.452, published at 65 FR 75378 and 67 FR 2136) and gas transmission pipelines\n(49 CFR 192, Subpart O, published at 68 FR 69778) to develop and follow individualized\nintegrity management (IM) programs, in addition to PHMSA's core pipeline safety\nregulations. The Integrity Management approach is designed to promote continuous\nimprovement in pipeline safety by requiring all operators to identify and invest in risk\ncontrol measures beyond core regulatory requirements existing today.\nBy not taking action, the Agency would be unresponsive to the congressional mandate in\nthe PIPES Act, and there would likely be no reduction in the number of deaths, injuries,\nor property damages associated with risks related to the integrity management of\ndistribution lines. Although this alternative would not lead to increased compliance costs,\nthere would be no reduction in the societal costs associated with the deaths, injuries, and\nproperty damages associated with integrity management improvements. This alternative\nresults in zero net benefits. Thus, this alternative is the baseline for comparison with other\nalternatives.\n11\n\n<<<PAGE 14>>>\n\n5.2 Apply existing gas transmission pipeline IM program regulations to gas\ndistribution pipelines\nThis alternative was determined by PHMSA to be infeasible.\nGas distribution pipelines are different from hazardous liquid and gas transmission\npipelines. Distribution systems combine main lines with an almost equal amount of\nmileage branching from the main lines to connect services to natural gas users. Lines are\ngenerally smaller in diameter, operate at much lower pressures, and are constructed of a\nvariety of materials, both metallic and non-metallic. Approximately half of the pipe in\ndistribution systems is plastic compared to very small amounts of plastic gas transmission\npipeline. To reach the many end users they serve, distribution pipelines include extensive\nbranching and interconnection compared to transmission systems that have long\niminterrupted runs of pipe. These differences substantially distinguish distribution\nsystems from transmission systems, and thus it is not technically feasible to apply gas\ntransmission integrity management requirements to distribution pipelines. For instance,\nthe low pressures, small diameters, and complex connections associated with distribution\nsystems make it infeasible to use smart pigs or hydrotesting, techniques that are used by\ntransmission lines for integrity management. Since a determination has been made that\nthis alternative is not technically feasible to implement, there has been no attempt to\nestimate impacts. Consequently, no further consideration was given to this alternative.\n5.3 Model State legislation, potentially imposing requirements on excavators and\nothers outside the jurisdiction of pipeline safety authorities\nThis alternative was determined by PHMSA to be infeasible because PHMSA could not\nensure that any or all of the States adopt the model State legislation.\nAccording to the Integrity Management for Gas Distribution Report of Phase I\nInvestigations, experience indicates that this option may not be practical for addressing\nthe broad question of integrity management. The group references the failure of State\nlegislatures to adopt an available model from the Common Ground effort to prevent\nexcavation damage.^\nIn studying the issue, the study group foimd that model State legislation may be useful for\nnarrower issues, such as improving excavation damage prevention through\nimplementation of comprehensive damage prevention programs, including active\nenforcement.^ The report concludes, \"There are many factors affecting State approaches\nto regulation. It would be very unlikely that all States could adopt model legislation with\nsufficient consistency that would represent a national solution to integrity management\nconcerns.\"\nThe group was composed of representatives of the natural gas distribution industry. State pipeline\nregulatory authorities, and the public. Integrity Management for Gas Distribution: Report of Phase I\nInvestigations,\" December 2005. Excavation Damage Group Report, p.71.\n^Ibid.p.71.\n12\n\n<<<PAGE 15>>>\n\nAfter careful study, this option is not considered any further as a means of addressing the\nentire integrity management issue, because the integrity management study group found\nthat the issues surrounding integrity management are broad and require a holistic\napproach at the Federal level. Not being operationally feasible, this alternative was not\nconsidered to be amenable to a comparison of the costs and benefits.\n5.4 Guidance documents for adoption by States with the intent of States mandating use\nof the guidance\nAs with the previous alternative, this alternative was determined by PHMSA to be\ninfeasible because PHMSA could not ensure that any of the States would mandate the use\nof the guidance, therefore distribution safety would not improve.\nThe Integrity Management for Gas Distribution Report of Phase I Investigations\ndetermined that this option is essentially the same as option 5.3 above, except it\ncontemplates States adopting the guidance as mandatory requirements. As with model\nlegislation, the study group considered that adoption likely would not occur in many\nStates. Although the Federal Government establishes basic safety standards, certified\nStates are responsible for regulating intrastate pipelines. The study group notes that States\ntypically have not uniformly adopted recommended approaches in the past. Selecting this\noption would thus provide only the illusion of a solution. The costs of such an approach\nwould be relatively low, but if the conclusions of the study group are correct, there would\nalso be low beijefits and perhaps, insignificant net benefits. For these reasons, this\nalternative was not considered any further.\n5.5 Prescriptive Federal regulation, specifying in detail actions that must be taken to\nassure distribution pipeline integrity\nThis alternative was determined by PHMSA to be too inflexible to be applicable to all\nrelevant situations that distribution system operators might confront.\nThe Integrity Management for Gas Distribution Report of Phase I Investigations\nreaffirms the need for a flexible Federal rule. The study group reasoned that a highly\ndetailed prescriptive regulation would eliminate the flexibility needed to address the\nunique circumstances of individual States and operators. The study group reported, \"The\nissues important to assuring the integrity of these diverse systems will vary. This\ndiversity makes it difficult for any one prescriptive requirement to address all possible\ncircumstances. It is important that any new requirements that are developed allow\nsufficient flexibility for the operators of distribution pipeline systems, and the State\nregulators who oversee their operations, to customize their integrity management efforts\nto address their specific systems, threats, and issues.\"'\"\nAlthough some small operators might prefer a prescriptive regulation, most large\noperators want the flexibility of a performance-based regulation. The wide range in size\nand nature of distribution pipeline systems calls for a flexible approach to integrity\n' Integrity Management for Gas Distribution. Report of Phase I Investigations. December 2005, p.13-14.\n13\n\n<<<PAGE 16>>>\n\nmanagement rather than a single detailed set of requirements. Giving operators the\nguidance and allowing them to shape it to fit their particular system will assure integrity\nmanagement efficiently and effectively. A detailed prescriptive rule was deemed by\nPHMSA to be too inflexible to be applicable to all relevant situations that distribution\noperators might face, since there is a wide spectrum of distribution operators, from\nmaster meter (mostly one-man operation) to large utilities covering thousands of miles of\npipelines and over a million customers. Thus a prescriptive rule would be inappropriate\nand ineffective, resulting in many operators being required to perform tasks not\nappropriate for their pipeline systems.' These statements of the rule being ineffective\nand inappropriate suggest that there would likely be a low level of net benefits. For these\nreasons a prescriptive Federal regulation was evaluated no further.\n5.6 Risk-based, flexible, performance-oriented Federal regulation, establishing high-\nlevel elements that must be included in integrity management programs\nThis alternative was determined by PHMSA to be practicable and is compared in this\ndocument with the baseline \"no action\" alternative. As will be demonstrated, there are\nsignificant net benefits associated with this alternative.\nThis alternative, that is the subject of the rule, creates a high-level, flexible, and\nperformance-based Federal regulation that requires gas distribution operators to develop\nand implement an integrity management program for their distribution pipeline systems.\nThe regulation requires all operators of a distribution pipeline system to implement an\nintegrity management program and would prescribe minimum requirements each\noperator must meet in doing so. An integrity management program is intended to\nmanage the risks associated with an operator's pipeline system.\nAn integrity management plan would address, at a minimum, the following elements:\n• Develop an understanding of their system, periodically reviewing and refining it\nas needed.\n• Identify threats (existing and potential).\n• Evaluate and rank risks.\n• Identify and implement measures to mitigate risks.\n• Measure performance, monitor results, and evaluate effectiveness.\n• Periodically re-evaluate risks and consider the relevance of threats.\n• Report results.\nThis also embraces the installation of EFVs. An operator would be required to install an\nEFV on newly installed or replaced service lines that operate continuously throughout the\nyear at a pressure not less than 10 psig and serve a single-family residence, imless doing\nso would not be practicable. This requirement applies only to new or replaced service\n\" Integrity Management for Gas Distribution: Report of Phase I Investigations,\"","truncated":true,"body_characters":168931}