{"operation":"document","citation":"0900006480e8a8db","title":"U.S. DOT/RSPA - Draft Final Regulatory Evaluation","source_type":"rulemaking","agency":"Pipeline and Hazardous Materials Safety Administration","status":"current","official":true,"published_on":null,"effective_on":null,"summary":"U.S. Department of Transportation Research and Special Programs Administration Final Regulatory Evaluation Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) Docket RSPA-00-7666 I The technical requirements, costs, and benefits associated with this altemative would be identical to those for the “no action” altemative, since the substantive technical requirements would be the same, i.e., those imposed by the Act. As described above, RSPNOPS determined that those requirements would result in...","machine_formats":{"json":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e8a8db.json","markdown":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e8a8db.md"},"app_url":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e8a8db","source_url":"https://downloads.regulations.gov/PHMSA-RSPA-2000-7666-0149/attachment_1.pdf","body":"<<<PAGE 1>>>\n\nU.S. Department of Transportation\nResearch and Special Programs Administration\nFinal Regulatory Evaluation\nPipeline Integrity Management in High Consequence Areas\n(Gas Transmission Pipelines)\nDocket RSPA-00-7666\n\n<<<PAGE 2>>>\n\nINTRODUCTION\nThe U.S. Department of Transportation Research and Special Programs Office of Pipeline Safety\n(RSPNOPS) is changing pipeline safety regulations to require operators of certain pipelines to\nvalidate the integrity of their pipelines in high consequence areas. The rule applies to operators of\nnatural and other gas transmission pipelines. The objective of the change is to reduce the risk of\npipeline incidents in these areas. High consequence areas are redefined in this rule. Under the\nredefinition, operators must choose one of two options to designate high consequence areas:\nA11 class 3 & 4 locations (these are areas where there are at least 46 buildings intended for\nhuman occupancy or where buildings with four or more stories above ground are prevalent\nwithin 660 feet of the pipeline along any continuous mile of its length) plus areas where a\npotential impact circle of radius greater than 660 feet includes 20 or more buildings\nintended for human occupancy, or\nLocations where the potential impact circle, of whatever size, includes 20 or more\nbuildings intended for human occupancy.\nUnder either option, pipeline operators must also include as high consequence areas any potential\nimpact circle that contains:\n8 A hospital, school, prison, day care center or other facility having persons who are\nconfined or of limited mobility, or\nOutdoor locations or open structures where 20 or more persons congregate at least 50 days\nin any 12-month period, or\n0 A building in which 20 or more persons gather 5 days a week for 10 weeks in any 12-\nmonth period (the days and weeks need not be consecutive).\nThe potential impact circle used in any of these determinations is a circle, centered on the\npipeline, of a radius calculated based on the size and pressure of the pipeline. The potential\nimpact circle approximates the area that could be affected by a rupture and subsequent explosion\noccurring on the pipeline.\nTo validate the integrity of their pipelines in high consequence areas under the regulatory change,\npipeline operators must implement an integrity management program for such pipelines including\nperiodic inspection and testing and integration of information related to pipeline integrity. The\npurpose of this report is to assess the benefits and costs of the regulatory change.\nThis rule is similar to rules promulgated earlier for hazardous liquid pipeline operators. High\nconsequence areas were defined differently for hazardous liquid pipelines, because the\n1\n. * .\n\n<<<PAGE 3>>>\n\nenvironmental consequences of leaks from hazardous liquid pipelines are different than those\nfrom natural gas pipelines. The elements of an integrity management program required by this\nrule are similar, however, to the elements previously required of hazardous liquid pipeline\noperators. This report considers the costs and benefits of these requirements in a manner similar\nto the analysis of costs and benefits prepared for the earlier rulemakings.\nTARGET PROBLEM\nNatural and other gas pipeline breaks can result in explosions and fires that can impact on human\nhealth and safety. The magnitude of this impact differs. There are some areas in which the\nimpact of a pipe break will be more significant than it would be in others due to concentrations of\npeople near the pipeline and who thus could be affected. Because of the potential for dire\nconsequences of pipeline failures in certain areas, these areas merit a higher level of protection.\nThe OPS is promulgating this regulation to afford the necessary additional protection to these\n“high consequence areas”.\nNumerous investigations by RSPNOPS and the National Transportation Safety Board (NTSB)\nhave highlighted the importance of protecting the public from pipeline failures. The NTSB has\nmade several recommendations to ensure the integrity of pipelines near populated areas. These\nrecommendations included requiring periodic testing and inspection to identify corrosion and\nother damage, establishing criteria to determine appropriate intervals for inspections and tests, and\ndetermining hazards to public safety from electric resistance welded pipe.\nCongress also directed RSPNOPS to undertake additional safety measures in areas that are\ndensely populated. These statutory requirements included having RSPNOPS prescribe standards\nfor identifjmg pipelines in high density population areas and issue standards requiring periodic\ninspections using internal inspection devices on pipelines in densely-populated areas.\nThis rulemaking addresses the target problem described above, and is a comprehensive response\nto the NTSB’s recommendations and Congressional mandates, as well as pipeline safety and\nenvironmental issues raised over the years.\nALTERNATIVES CONSIDERED\nThe OPS considered several alternatives to provide the necessary increased level of protection to\nhigh consequence areas. These alternatives were:\n1. No action.\n2. Publishing a rule that would adopt requirements of the Pipeline Safety Improvement Act of\n2002 and establish procedures to seek waiver of reassessment intervals\n3. Prescriptive requirements for inspection and repair of pipelines in high consequence areas.\n4. Requiring pipeline operators to develop integrity management programs providing for\ninspection and testing based on risk factors and integration of information related to pipeline risk.\n2\n\n<<<PAGE 4>>>\n\n5 . Requiring pipeline operators to develop integrity management programs providing for\nexpedited inspection and testing.\nINITIAL SCREENING OF ALTERNATIVES\n1 . No action.\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. In this case,\nhowever, the “no action” alternative does not maintain the status quo. The status quo has been\nchanged by Act of Congress.\nThe Pipeline Safety Improvement Act of 2002 (PSIA-2002), signed into law on December 17,\n2002, imposes requirements directly on pipeline operators. To be sure, PSIA-2002 directs the\nSecretary of Transportation to publish, within one year, standards for integrity management plans\nthat would require periodic assessment of pipelines in high consequence areas. PSIA-2002 goes\non to require that operators of gas transmission pipelines, regardless of whether or not the\nSecretary publishes such standards, must conduct a risk analysis, implement integrity management\nprograms, and begin baseline assessments of their pipeline facilities in high consequence areas\nwithin 18 months. Baseline assessments must be completed on all gas transmission pipeline\nsegments in high consequence areas within 10 years. Each ‘gas transmission pipeline segment in a\nhigh consequence area must be reassessed at least every 7 years.\nThe assessment requirements in PSIA-2002 apply to “each of the operator’s facilities in areas\nidentified pursuant to subsection (a)( 1) [of 49 U.S.C. 0 601 091 and defined in chapter 192 of title\n49, Code of Federal Regulations, including any subsequent modifications” (emphasis added)’.\nThe cited provision of the U.S. Code is the legislative requirement that the DOT establish criteria\nfor identifying pipelines in high-density population areas, or high consequence areas. The\nreference to the definition in title 49 of the Code of Federal Regulations is thus a reference to the\ndefinition of high consequence areas established by DOT. The applicability of the Act’s\nrequirements to any “subsequent modifications” of that definition allows the DOT to revise its\ncriteria and further focus the actions required of pipeline operators. Absent a change to the\ndefinition embodied in part 192, however, operators would be required to conduct assessments of\nall pipeline segments meeting the current definition.\nRSPNOPS, in fact, has been considering changes to the definition of high consequence areas in\npart 192 to further refine the criteria and to focus better on areas most at risk and for which special\nrequirements are appropriate. Making those changes would reduce the amount of pipeline on\nwhich integrity assessments are required to be performed without significantly reducing the\n‘Pipeline Safety Improvement Act of 2002, Section 14, “Risk Analysis and Integrity Management Programs\nfor Gas Pipelines”\n3\n\n<<<PAGE 5>>>\n\nbenefits to be realized from those assessments.\nPSIA-2002 requires that the pipeline assessments specified in the Act must be conducted using in-\nline inspection, pressure testing, or direct assessment. The Act also allows assessments to be\nconducted using “an alternative method that the Secretary [of Transportation] determines would\nprovide an equal or greater level of safety”.’ Here, again, RSPNOPS has been considering\nadditional methods for conducting assessments. Confirmatory Direct Assessment (CDA) was\ndiscussed in the proposed rule for integrity management in gas transmission pipelines.’ This\nmethod allows for assessment of pipeline integrity at less cost to operators and resulting in less\npotential interruption in pipeline operations. In addition, RSPNOPS has been considering\nalternative methods of assessing low-pressure pipeline, for which pipe wall stresses are much\nlower and failure by leakage is much more likely than ruptures, which would also provide\nassurance of integrity at less cost than the methods specified in PSIA-2002.\nTaking no action would leave the definition of high consequence areas in part 192 unchanged. It\nwould also mean that no alternative method, other than those specified in PSIA-2002, could be\ndefined for conducting assessments of gas transmission pipelines in high consequence areas. The\nresult would be conduct of assessments on more pipeline than is needed to address the underlying\nsafety issue using more expensive assessment methods. RSPNOPS evaluated the costs operators\nwould incur under this alternative, as described in the appendix to this analysis, and found that\nthey would be significantly higher than those that would result from other alternatives.\nIn addition, taking no action would not be responsive to the requirement in PSIA-2002 that DOT\n“issue regulations prescribing standards to direct an operator’s conduct of a risk analysis and\nadoption and implementation of an integrity management program.’* , ’\nFor these reasons, the “no action” alternative was not considered further.\n2. Publishing a rule that would adopt requirements of the Pipeline Safety Improvement Act of\n2002 and establish procedures to seek waiver of reassessment intervals\nPSIA-2002 allows the Secretary of Transportation to waive or modi@ requirements for\nreassessments for reasons that may include the need to maintain local product supply or the lack\nof internal inspection devices, provided that such a waiver is not inconsistent with pipeline safety.\nAnother alternative would be to publish a rule that adopts the substantive requirements of PSLA-\n2002, without change, but establishes procedures for approving the allowed waivers.\n’bid.\n’Federal Register, January 28,2003 (68 FR 4278), “49 CFR 192, Pipeline Safety: Pipeline Integrity\nManagement in High Consequence Areas (Gas Transmission Pipelines); Proposed Rule”.\n‘hpeline Safety Improvement Act of 2002, Section 14, “Risk Analysis and Integrity Management Programs\nfor Gas Pipelines”\n4\n\n<<<PAGE 6>>>\n\nI\nThe technical requirements, costs, and benefits associated with this altemative would be identical\nto those for the “no action” altemative, since the substantive technical requirements would be the\nsame, i.e., those imposed by the Act. As described above, RSPNOPS determined that those\nrequirements would result in unnecessary expense for assessments, using the most costly methods\nto address more pipeline than RSPNOPS has determined is necessary to address the underlying\nsafety need.\nFor this reason, the option of publishing a rule that only establishes procedures for waivers was\nnot evaluated further.\n3. Prescriptive requirements for inspection and repair of pipelines in high consequence areas and\nfor incorporating accident mitigative features.\nPipeline circumstances differ, even within high consequence areas. These differences would\nmake it difficult, at best, to establish prescriptive requirements that would appropriately address\nall possible combinations of pipeline size, type, and configuration or to consider other factors that\ncontribute to the risk of failure of a particular pipeline. It is likely that creating detailed\nprescriptive requirements would result in a need for a large number of waivers to address the\nissues of importance to specific pipelines and high consequence areas. The result would be a\npatchwork of specific, but different requirements. It would be an ineficient use of industry and\ngovernment resources to establish requirements in this fashion.\nPrescriptive requirements also would tend to stifle technological innovation. They do not allow\nfor different approaches based on advances in the technology. The technology associated with in-\nline inspection of pipelines (i.e., pigging) is advancing at a rapid pace. Establishhg prescriptive\nrequirements could slow this advancement, or could preclude use of new techniques that may be\ndeveloped. In the extreme, prescriptive requirements could stop technological innovation in this\narea completely.\nEstablishing prescriptive requirements would not assure the integration of information, which\nexperience has shown is vital to preventing pipeline accidents. Two major pipeline accidents\nhave occurred in recent years despite the fact that information about the causative factors should\nhave, or could have, been known - at Edison Township, NJ and Carlsbad, NM. In the first case,\nin-line inspection (pigging) of the pipeline had taken place. The operator either failed to identify,\nduring the pig runs, the areas of damage that eventually caused the rupture or the damage occurred\nin the years following the inspection. In addition, the operator failed to integrate information\nabout the pipeline, including the presence of significant construction activity in the area, in a\ncontinuing assessment of the line’s integrity. In the latter case, the accident resulted from internal\ncorrosion due to collection of moisture in a low spot which could not be inspected by pigging.\nThe operator failed to consider the possibility of such accumulation of moisture and resulting\ncorrosion and thus did not intercede to prevent the pipeline failure. It appears that information\nwas available that, if correlated to current pig results (in the case of Edison Township) or other\ninformation about the pipeline, could have highlighted the need for action regarding the problems\n5\n8\n\n<<<PAGE 7>>>\n\n,\nthat ultimately resulted in failure of the pipe.\nAn integrity management program is required to assure this integration of available information.\nOutside review of the integrity management program by regulators (Federal and state), is\nnecessary to assure that it is complete and properly implemented. This outside review cannot be\nassured without a requirement for such a program that establishes the requirements against which\nsuch a review will be conducted.\nMost importantly, establishing prescriptive requirements would not be consistent with\nrequirements imposed by PSIA-2002. The Act requires that DOT prescribe rules to direct an\noperator’s conduct of a risk assessment and adoption and implementation of an integrity\nmanagement program. Prescriptively establishing when and where integrity assessments must be\nperformed would be inconsistent with the requirements of the Act.\nFor these reasons, the option of establishing prescriptive requirements was not evaluated further.\n4. Requiring pipeline operators to develop integrity management programs providing for\ninspection and testing based on risk factors and integration of information related to pipeline risk.\nPipeline operators are uniquely qualified to develop integrity management programs and provide\nfor the necessary integration of information. They have the best knowledge of their pipelines and\nthe factors affecting its risk. Integration of information requires that the management systems of\nthe company be aligned and operated to assure that necessary information is shared and that it is\nevaluated in its proper context by knowledgeable personnel. These are actions that are difficult to\nrequire through prescriptive regulation. Requiring that operators develop such programs is the\nbest way to assure that they occur. Such a requirement also provides the regulatory basis for\nRSPNOPS and states to audit, review, and assess these programs and their implementation.\nThe best integrity management plans, when implemented properly, can reduce the risk of pipeline\naccidents. They cannot, however, eliminate that risk. Leaks and ruptures could still occur, from\nunforeseen outside impacts on the pipeline or from unanticipated interactions among factors\ncontributing to pipeline risk. It is therefore important that features and procedures be available to\nmitigate the effects of accidents that may occur.\nHere again, circumstances differ between pipelines and between regions and local jurisdictions.\nThe differences make it difficult to establish prescriptive requirements that will provide the best\nprotection for each high consequence area. Requiring that operators explicitly consider the need\nfor mitigative features and provisions and that they implement those found necessary is the most\neffective means of providing such protection. Such a requirement also provides the regulatory\nbasis for audit and review by RSPNOPS and state regulators.\nEstablishing requirements for operators to develop and adopt integrity management programs is\nalso most consistent with the requirements imposed on DOT by PSIA-2002. This option also\n6\n\n<<<PAGE 8>>>\n\nallows RSPNOPS to make changes in the definition of high consequence areas to improve the\n'\nfocus of the new requirements, and to establish altemative methods that are acceptable for,\nperforming integrity assessments. Both of these changes will reduce the costs imposed on\nindustry without significantly reducing the benefits to be realized.\nFor these reasons, this option was selected for further development.\n5. Requiring pipeline operators to develop integrity management programs providing for\nexpedited inspection and retesting.\nRSPNOPS considered the need for requiring integrity management programs that would require\ninspection and testing of pipelines to recur over short intervals, e.g., a few years. The ability to\nrequire frequent testing is limited by the available resources for testing and inspection.\nThe companion rule covering hazardous liquid pipelines requires reassessments at least every five\nyears, with limited exceptions. The current capacity to perform pipeline inspections will be\nchallenged by this required schedule. The OPS concluded that the spur provided by the regulation\nwould be likely to result in an increase in testing capacity over the next five years that will then be\nable to accommodate testing at accelerated rates. The OPS also concluded that protection from\nenvironmental damage that can be caused by a leak or rupture of a hazardous liquid pipeline, and\nthe occurrence in hazardous liquid pipelines of frequent pressure cycles that can cause defects to\ngrow, necessitated such frequent inspection. Adding requirements for similarly frequent\ninspection of natural gas pipelines would complicate the existing testing capacity issue and likely\nmake it difficult for any of the testing requirements to be met.\n, '\nExisting regulations already provide some additional protection from accidents on gas\ntransmission pipelines that could affect high consequence areas.' The requirements of 49 CFR\n192.61 1 specify that pipelines in class 3 or 4 areas must operate at pressures that produce\nsignificantly lower hoop stresses in the pipe than is allowed in more rural areas. As a practical\nmatter, operators meet this requirement by reducing operating pressure or using heavier-walled\npipe in class 3 and 4 areas. Hazardous liquid pipelines do not afford similar protection in high\nconsequence areas. The additional protection already provided by natural gas transmission\npipelines justifies assessment on a more extended interval than for hazardous liquid pipelines.\nAdditionally, the natural gas pipeline network supplies gas for use in real time. This is not the\ncase for hazardous liquid pipelines, which move product in batches and have significant storage\ncapacity. Assessment of natural gas pipelines can therefore result in interruptions of gas supply.\nThis can have a safety impact, in addition to its economic effect, due to the need to restart gas\nservice in a controlled manner so as to avoid explosions at the point of service. The likelihood of\nservice interruptions, with attendant costs and safety concerns, increases as the assessment\ninterval is shortened, since operators have less flexibility to conduct assessments at times when\ndemand is lower.\n7\n\n<<<PAGE 9>>>\n\nFinally, significant environmental damage is not expected to result from failure of a natural gas\npipeline, unlike hazardous liquid pipelines, since gas is lighter than air and dissipates in the ’\natmosphere.\nThe PSIA-2002 requires reassessments on no greater than 7-year intervals. This altemative would\nbe similar to the “no rule” option in that it would require assessments using in-line inspection,\npressure testing, or direct assessment at no more than seven year intervals. The OPS has\nestablished requirements in this rule that would provide for a more focused assessment on this\nshorter interval, to reduce the likelihood of supply interruptions. As described above and in the\nappendix, RSPNOPS has evaluated the costs of options that do not allow the revised scope for 7-\nyear inspections. Costs would increase significantly without addition of commensurate benefits.\nFor these reasons, RSPNOPS concluded that assessment of natural gas pipelines need not be\nrequired as frequently as for hazardous liquid pipelines.\nBASELINE REGULATORY ENVIRONMENT\nIn order to assess the costs and benefits of the new regulation, it is necessary first to ascertain the\ncurrent level of activity in areas addressed by the rule. As described above, legislation recently\nenacted will impose a change in this level of activity, requiring the implementation of integrity\nmanagement plans and conduct of integrity assessments that have not previously been performed.\nStill, it is necessary to determine the level of activity that has been occurring. The costs, and\nbenefits, of implementing either this rule, or the requirements of PSIA-2002 without a rule, must\nbe measured against this historical background. In this instance, it is necessary to determine the’\nrate at which pipeline inspections are being performed, and the prevalence and nature of integrity\nmanagement plans similar to those required by the rule.\nRSPNOPS has interacted with gas pipeline operators in recent years as part of development of an\nintegrity management standard by the American Society of Mechanical Engineers (ASME). The\nstandard includes many of the elements of this rule, and has been adopted as a consensus standard.\nAs a result of these interactions, RSPNOPS understands that some gas pipeline operators\ncurrently have, or are developing, integrity management programs including many aspects\nrequired by this regulation.\nThese current integrity management programs include inspection of their pipelines by some\noperators. The amount of such inspection is relatively low, however. Much of the testing being\nconducted by these operators is the initial inspection of pipelines. The rate at which subsequent\ninspections would be performed is now unknown. It is likely that some pipeline would be\nidentified for reinspection routinely (e.g., every ten years). It is equally likely that some pipeline\nwould not be reinspected at all.\nIntegrity management plans are a key element of this rule. To better understand and promote\n8\n\n<<<PAGE 10>>>\n\nmore comprehensive and integrated approaches to safety and environmental protection,\nRSPNOPS created the Risk Management Demonstration Program, and the System Integrity\nInspection Pilot Program. These programs encourage and evaluate operator-developed safety and\nenvironmental management processes that incorporate operator- and pipeline-specific information\nand data to identify, assess, and address pipeline risks. These programs are helping RSPA’s\nOffice of Pipeline Safety refine its regulatory oversight processes. These processes help to ensure\nthat pipeline operators have effective processes in place to identify the most important risks to the\npublic and the environment, and to develop and implement cost-effective preventive and\nmitigative actions to manage these risks. Many of these initiatives have validated the importance\nof focusing resources and establishing higher levels of protection in areas where a pipeline failure\ncould have significant consequences.\nThrough the Risk Management Demonstration Program and the System Integrity Inspection Pilot\nProgram, RSPNOPS has improved its understanding of pipeline operator integrity management\nsystems and activities. This experience has shown that a number of pipeline operators have\nformalized management systems to identify and address the most significant integrity threats to\ntheir pipeline systems. In the Risk Management Program, participants perform systematic and\ncomprehensive risk assessments to identify the specific nature and location of the most significant\nrisks posed by operation of their pipeline system. An essential feature of these risk assessments is\nthe integration of information from many diverse sources to hlly understand the integrity threats\nat specific locations on the pipeline. The impact on nearby population is explicitly considered in\nthese risk assessments. Through formal, risk-based decision making processes, these companies\nuse the risk assessment results to identify projects and activities that address potential system\nintegrity threats, thereby preventing leaks and accidents. These investigative risk management\nprograms, and the preventive and mitigative risk control activities that evolve from them,\nsupplement the minimum regulatory requirements established in 49 CFR 192.\nThe System Integrity Inspection Program is focused on developing a more integrity-based\napproach to RSPNOPS inspections. Instead of using a “checklist” approach, RSPNOPS is\nfocusing the inspection process on an operator’s integrity management processes and activities.\nThrough working with the operator, RSPNOPS is able to understand and influence the methods\nand approaches used to assess pipeline integrity, and the approaches to integrating integrity\nassessment data with other pipeline specific information, to identify the most significant integrity\nthreats to the system. Specifically, RSPNOPS has observed how operators examine internal\ninspection data in conjunction with other surveillance and operating data, expected population\ngrowth, land use, construction activity along the pipeline, and other information relevant to\nassuring the integrity of the pipeline in high population areas and in environmentally sensitive\nareas. Through this interaction RSPNOPS is acquiring a broader understanding and a greater\nconfidence that effective programs are in place to address the most significant risks. Similar to\nthe Risk Management Program, the SII Program is emphasizing how operators evaluate their\nsystem condition and its risks, and use this information to make sound integrity management\ndecisions.\n9\n\n<<<PAGE 11>>>\n\nThe RSPNOPS experience in the Risk Management Demonstration Program and the System\nIntegrity Inspection Program indicates that integrity management programs including many of the\nelements required by this rule have been developed. They are far from universal, however.\nCONSIDERATION OF PUBLIC COMMENTS\nA number of comments were received in response to the proposed rule (68 FR 4278) and the\nregulatory analysis supporting it (referred to herein as the draft regulatory analysis). Comments\nfrom industry generally agreed that the earlier analysis had significantly underestimated the costs\nof complying with the proposed rule. The Interstate Natural Gas Association of America\n(INGAA) and the American Gas Association (AGA) made specific recommendations for changes\nto the proposed rule. In each case, the associations provided estimates of the costs, and savings,\nthat would result from their changes.\nRSPNOPS acknowledges that the earlier regulatory analysis underestimated the costs of\ncomplying with the proposed rule. There were two principal reasons for this understatement.\nFirst, RSPNOPS used outdated information for estimating the costs of performing modifications\non pipelines (e.g., to accommodate in-line inspection devices) and to perform inspections. The\nRSPNOPS estimates were based on studies that were performed in the early 1990s. Costs had\nbeen escalated to 2001 using the producer price index (i.e., to reflect inflation). Changes since\n1990 in how this work must be performed, particularly costs associated with complying with\nimproved environmental standards, significantly outpaced inflation during this period.\nRSPNOPS acknowledges this deficiency. For this analysis, RSPNOPS has adopted the unit\ncosts (i.e., costs per mile or costs per company) used by INGAA and AGA in their analyses, as\ndescribed herein for individual cost elements.\nThe unit costs used by INGAA and AGA in their cost estimates differ. AGA explains the reason\nfor this difference as the higher costs to do any kind of work, particularly work requiring\nexcavation, in the urban environment in which its members operate. RSPNOPS acknowledges\nthat costs are likely higher for urban work, and agrees that use of different unit costs for\ncompanies in such areas is reasonable. RSPNOPS has restructured this analysis to estimate costs\nseparately for companies operating long-distance transmission pipelines in mostly rural areas\n(similar to INGAA members) and those operating transmission pipelines in urban areas (similar to\nAGA members). Unit costs derived from INGAA comments have been used for the long-distance\nestimates, and those from AGA’s comments are used to estimate costs for companies in urban\nenvironments. (RSPNOPS has also updated the estimated costs associated with the proposed\nrule, using the new unit costs. These estimates are provided in the appendix, in order to illustrate\nthe effect on costs of changes made between the proposed rule and the final rule).\nSecond, RSPNOPS used a much lower estimate for the amount of “overtesting” that will occur\nthan used by INGAA in its analysis. Overtesting refers to pipeline not in high consequence areas\nthat must be tested in order to test segments of pipeline that are within those areas. This\n10\n\n<<<PAGE 12>>>\n\nprincipally affects in-line inspection (i.e., pigging). Inspection tools (i.e., pigs) must be inserted\ninto the pipeline, run over the length of pipe to be inspected, and removed. Insertion and removal\nmust occur at locations where there are launchers and receivers, structures attached to the pipeline\nwhich allow for insertion and removal of these large tools. RSPNOPS's preliminary draft\nregulatory analysis in support of the proposed rule had estimated the amount of overtesting as 25\npercent (i.e., for every 10 high consequence area miles tested, 12.5 total miles would be tested).\nThe Technical Pipeline Safety Standards Committee recommended that this assumption be\nincreased when it reviewed the preliminary draft regulatory analysis. That analysis was' changed\nto assume 200 percent overtesting. ,\nThe comments submitted by INGAA and AGA used different estimates for overtesting. AGA\nassumed 100 percent overtesting for pigging, and no overtesting for pressure testing or direct\nassessment. This reflects that a significant portion of the transmission pipeline mileage of AGA\nmembers is likely to be in high consequence areas and that the distance between pig launchers and\nreceivers in urban areas is relatively short. INGAA did not report a percentage assumption for\novertesting. Instead, INGAA surveyed its members to obtain an estimate of the number of miles\nthat they believed would be classified as high consequence areas and the number of miles that\nwould have to be tested in order to pig those segments. The total number of miles that would be\ninspected was reported to be 7.25 times the estimated length of the high consequence area\nsegments. RSPNOPS finds that this factor, while considerably higher than the 200 percent\novertesting assumed in the draft analysis, is reasonable. High consequence areas are likely to be\nwidely dispersed on long-distance transmission pipelines. The distance between pig launchers\nand receivers on those pipelines is relatively long, on the order of 50 miles. The combination of\nthese factors makes it likely that a significant amount of overtesting will occur on these pipelines.\nRSPNOPS has adopted, for purposes of this analysis, an assumption of 625 percent overtesting,\nfor pigging, consistent with the results of the INGAA survey. INGAA assumed 25 percent\novertesting for pressure testing, which is the same factor RSPNOPS uses in this analysis. There\nis no overtesting required for assessments performed by direct assessment.\nINGAA also commented that the draft regulatory analysis underestimated the costs associated\nwith data integration. The draft analysis had assumed that this would cost $100,000 in the first\nyear for each company operating more than 40 miles of transmission pipeline and $50,000\nannually thereafter. (The corresponding numbers for operators with fewer transmission miles\nwere $25,000 and $12,500 respectively). INGAA agreed that more costs would be incurred in the\nfirst year, when record systems must be realigned and older records, many in paper form, must be\nconverted for later analysis. INGAA estimated that the costs to perform this work would be\n$1,359 per mile in the first year, and $1 13 per mile annually thereafter. RSPNOPS agrees that\nestimating these costs on a per-mile basis (as opposed to per-company) is more reasonable, since\nthe number of records that must be considered is proportional to the amount of pipeline an\noperator has. RSPNOPS also accepts that the costs for retrieval and conversion of older, paper\nrecords is likely to be high. RSPNOPS has adopted the INGAA per-mile estimates for estimating\nthe cost of data integration.\n11\n\n<<<PAGE 13>>>\n\nCommenters also addressed the benefits of the proposed rule. Carol Parker noted that the\nCarlsbad accident had a significant economic impact on the state of California due to reductions\nin gas delivery following the accident. Ms. Parker suggested that avoiding future economic\nimpacts of this type is a benefit reasonably attributable to this rule. RSPNOPS agrees.\nRSPNOPS has estimated the magnitude of the economic impact that the Carlsbad accident had\non California and describes that in this analysis among the benefits of the final rule.\nREVIEW BY TECHNICAL PIPELINE SAFETY STANDARDS COMMITTEE\nThe OPS presented a preliminary draft of this regulatory analysis to the Technical Pipeline Safety\nStandards Committee (TPSSC) at a public meeting (conducted by teleconference) on July 3 1,\n2003. TPSSC is a Federal advisory committee charged with responsibility for advising on the\ntechnical feasibility, reasonableness, cost-effectiveness, and practicability of gas pipeline safety\nstandards. The TPSSC, by law, serves as the peer reviewer for RSPNOPS regulatory analyses.\nThe TPSSC noted that the provisions of PSIA-2002 impose restrictions that make it difficult to\noptimize the costs and benefits of the rule. In particular, the Act requires that pipeline segments\nin high consequence areas be subjected to baseline assessments within 10 years and be reassessed\nevery seven years. This has two effects.\n0 It results in an “overlap” period in the eighth, ninth, and tenth years after the law was\nenacted, in which both baseline and reassessments will be performed. The increased level\nof testing in these years increases costs and increases the likelihood that pipelines being\ntaken out of service for assessment will result in curtailment of gas supply\nIt requires pipelines to be inspected more frequently than is likely needed, particularly for\npipelines operating at low stress levels.\nThe TPSSC acknowledged that RSPNOPS had done as much as possible, within the restrictions\nof the Act, to minimize the effect of these restrictions. The committee unanimously found that the\ncost-benefit analysis supported going forward with the final rule.\nSCOPE AND PARAMETERS OF ANALYSIS\nThis analysis of benefits and costs takes the following approach. First, the mileage impacted by\nthe regulatory change is identified and estimated. Mileage is estimated separately for long-\ndistance transmission pipeline operators (representative of INGAA members) and for local\ndistribution companies (LDC, representative of AGA members). Then the potential benefits of\nthe rule are discussed. In the next section the potential costs of the rule are examined. Costs are\nestimated separately for long-distance operators and LDCs, due to the differences in unit costs for\nwork done by each class of operator (as discussed above). Finally, a discussion of the costs versus\nthe benefits is presented. It should be noted that, unless otherwise specified, all dollar values in\n12\n‘ 1 .\n\n<<<PAGE 14>>>\n\nthis report are given in constant 2001 dollars.' Furthermore, this analysis will arbitrarily consider\nonly the first twenty years after the effective date of the final rule. Including additional years\nwould not be expected to materially affect the conclusions of this analysis.\nANALYSIS\nImpacted Mileage\nIn this section the total pipeline mileage impacted by the regulatory change is estimated. That\nmileage is located in or nearby high consequence areas, defined by the change as areas in which\ndefined numbers of people or facilities housing people of limited mobility are within specified\ndistances of the pipeline. The distances vary depending on the diameter of the pipe and the\npressure at which it operates.\nTotal Pipeline Mileage\nIn total, there is an estimated 285 tilousand miles of regulated onshore natural gas transmission\npipelines in the U.S.6 This rule would not apply to all of this mileage. The principal requirements\nof the final rule apply to pipeline mileage in high consequence areas, which is estimated below.\nThe rule also applies to transmission pipelines for hydrogen, synthetic gas and other products\nsubject to 49 CFR Part 192 that are not included in the natural gas transmission pipeline totals.\nRSPNOPS does not have data on the total transmission mileage for these other gases. This\nanalysis uses the available natural gas transmission pipeline total mileage, which is considered to\nbe very close to the total pipeline mileage potentially affected by the regulation.\nImpacted MileaEe in High Consequence Areas\nThe major elements of the regulatory change apply to that transmission pipeline that is in high\nconsequence areas. The rule provides two options for an operator to determine whether a segment\nof pipeline is in a high consequence area. Under option a, all pipeline in class 3 and 4 areas, as\ndefined in 49 CFR 192.5, would be included, as well as additional pipeline having an identified\nsite within a potential impact circle. Under option b, operators would determine what pipe is in\nhigh consequence areas by evaluating potential impact circles along the entire pipeline.\n'Dol","truncated":true,"body_characters":206512}