{"operation":"document","citation":"0900006480e8d47b","title":"U.S. DOT/RSPA - Draft Final Regulatory Evaluation- Pipeline Integrity Management in High Consequence Areas (Gas Transmission Operators)","source_type":"rulemaking","agency":"Pipeline and Hazardous Materials Safety Administration","status":"current","official":true,"published_on":null,"effective_on":null,"summary":"DRAFT U.S. Department of Transportation Research and Special Programs Administration Draft Final Regulatory Evaluation Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) Docket RSpA-00-7666 c for different approaches based on advances in the technology. The technology associated with in- line inspection of pipelines (i.e., pigging) is advancing at a rapid pace. Establishing prescriptive requirements could slow this advancement, or could preclude use of new techniques that may be developed. In the extreme,...","machine_formats":{"json":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e8d47b.json","markdown":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e8d47b.md"},"app_url":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e8d47b","source_url":"https://downloads.regulations.gov/PHMSA-RSPA-1998-4470-0064/attachment_1.pdf","body":"<<<PAGE 1>>>\n\nDRAFT\nU.S. Department of Transportation\nResearch and Special Programs Administration\nDraft Final Regulatory Evaluation\nPipeline Integrity Management in High Consequence Areas\n(Gas Transmission Pipelines)\nDocket RSpA-00-7666\nc\n\n<<<PAGE 2>>>\n\nINTRODUCTION\nThe U.S. Department of Transportation Research and Special Programs Office of Pipeline Safety\n(OPS) is proposing to change pipeline safety regulations to require operators of certain pipelines\nto validate the integrity of their pipelines in high consequence areas. The rule would apply to\noperators of natural and other gas transmission lines. The objective of the change is to reduce the\nrisk of pipeline incidents in these areas. The OPS defines a high consequence area as:\n0 All class 3 & 4 locations. These are areas where there are at least 46 buildings intended\nfor human occupancy or any buildings with four or more stories above ground within 660\nfeet of the pipeline along any continuous mile of its length.\n0 Locations where any hospital, school or other facility having persons who are confined or\nof limited mobility are in a circular impact zone having radius equal to a “threshold\nradius” defined based on the diameter and operating pressure of the pipeline.\n0 Locations where 20 or more persons congregate at least 50 days in any 12-month period\nare in this circular impact zone\n0 Locations where the radius of the circular impact zone exceeds 660 feet and where any\ncircle of 1000 A. radius (or larger for some large-diameter, high-pressure pipelines)\ncentered on the pipeline includes 20 or more buildings intended for human occupancy.\nThe 20 building limit has been established to ensure the same building density as in Class\n3 Locations (see above).\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\nenvironmental consequences of leaks from hazardous liquid pipelines are different than those\nfrom natural gas pipelines. The elements of an integrity management program proposed to be\nrequired by this rule are similar, however, to the elements previously required of hazardous liquid\npipeline operators. This report considers the costs and benefits of these proposed requirements in\na manner similar to 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\n1\n\n<<<PAGE 3>>>\n\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 the OPS and the National Transportation Safety Board (NTSB) have\nhighlighted the importance of protecting the public from pipeline failures. The NTSB has made\nseveral recommendations to ensure the integrity of pipelines near populated areas. These\nrecommendations included requiring periodic testing and inspection to identi@ corrosion and\nother damage, establishing criteria to determine appropriate intervals for inspections and tests, and\ndetermining hazards to public safety &om electric resistance welded pipe.\nCongress also directed the OPS to undertake additional safety measures in areas that are densely\npopulated. These statutory requirements included having the OPS prescribe standards for\nidentifying 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 altematives were:\n-\n_ _ __ --------____ppp--___p p~\n2. Prescriptive requirements for inspection and repair of pipelines in high consequence areas.\n3. 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.\n4. Requiring pipeline operators to develop integrity management programs providing for\nexpedited inspection and testing.\nINITIAL SCREENING OF ALTERNATIVES\n1. No action.\nPipeline operators currently manage their pipeline to avoid accidents. They perform inspection\nand testing on their pipelines to assess their integrity, and make repairs as they conclude they are\nneeded. These actions would be expected to continue under the “no action” alternative.\nPipeline leaks and ruptures occur, despite the existence of these operator programs. Major\n2\n\n<<<PAGE 4>>>\n\npipeline accidents have occurred in recent years, of which two were particularly notable, at Edison\nTownship, NJ and Carlsbad, NM. In the first case, in-line inspection (pigging) of the pipeline had\ntaken place. The operator either failed to identify, during the pig runs, the areas of damage that\neventually caused the rupture or the damage occurred in the years following the inspection. In\naddition, the operator failed to integrate information about the pipeline, including the presence of\nsignificant construction activity in the area, in a continuing assessment of the line’s integrity. In\nthe latter case, the accident resulted fiom internal corrosion due to collection of moisture in a low\nspot which could not be inspected by pigging. The operator failed to consider the possibility of\nsuch accumulation of moisture and resulting corrosion and thus did not intercede to prevent the\npipeline failure. An integrity management program involving integration of all safetpsignificant\ninformation about the pipeline could have prevented both of these accidents. The OPS concludes\nthat validation of operator’s integrity management programs through audit and review by outside\nparties, Le, the regulator, is necessary to help assure that appropriate actions are taken.\nIn addition, continuation of voluntary programs cannot be assured absent some regulatory\nrequirement. In the absence of requirements, pipeline operators might choose to curtail or\neliminate some or all inspection and testing.\nThe OPS concludes that assuring continuation of pipeline integrity management programs,\nassuring that their scope encompasses all areas requiring special protection, and verifying their\nadequacy are necessary to assure that the requisite level of protection will be provided. This\nassurance cannot be provided without some regulatory requirement addressing the target problem.\nIn addition, continued reliance on voluntary industry efforts would not be responsive to the\nCongressional mandate that the OPS promulgate requirements to assure protection of the areas\nthat are herein designated as high consequence areas.\nFor these reasons, the “no action” alternative was not considered M e r . ~-\n2. 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 inefficient use of industry and\ngovernment resources to establish requirements in this fashion. Compliance inspection would\nstill require that the requirements applicable to specific pipelines be identified for comparison\nwith ongoing practices.\nPrescriptive requirements also would tend to stifle technological innovation. They do not allow\n3\ni\n\n<<<PAGE 5>>>\n\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. Establishing 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.\nMost importantly, however, establishing prescriptive requirements would not assure the\nintegration of information which experience has shown is vital to preventing pipeline accidents.\nAs noted above, two major accidents have occurred in recent years despite the fact that\ninformation about the causative factors should have, or could have, been known. It appears that\ninformation was available that, if correlated to current pig results (in the case of Edison\nTownship) or other information about the pipeline, could have highlighted the need for action\nregarding the problems that ultimately resulted in failure of the pipe. An integrity management\nprogram is required to assure this integration of available information. Outside review of the\nintegrity management program by regulators (Federal and state), is necessary to assure that it is\ncomplete and properly implemented. This outside review cannot be assured without a\nrequirement for such a program.\nFor these reasons, the option of establishing prescriptive requirements was not evaluated further.\n3. 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 idormation requires that the management systems of\nthe company be aligned and operated to assure that necessary information is shared and that it is\n- __ ---evaluatebin its ~ ~ c ~ ~ ~ - ~ ~ ~ areactionsdmtare difficulta -\nrequire through prescriptive regulation. Requiring that operators develop such programs is the\nbest way to assure that they exist. Such a requirement also provides the regulatory basis for the\nOPS 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, fiom\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\n4\n\n<<<PAGE 6>>>\n\nbasis for audit and review by OPS and state regulators.\nFor these reasons, this option was selected for fiuther development.\n4. Requiring pipeline operators to develop integrity management programs providing for\nexpedited inspection and retesting.\nThe OPS considered the need for requiring integrity management programs that would require\ninspection bnd testing of pipelines to recur over short intervals, a few years. The ability to require\nfiequent 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 fiom\nenvironmental damage that can be caused by a leak or rupture of a hazardous liquid pipeline\nnecessitated such frequent inspection. Adding requirements for similarly hquent inspection of\nnatural gas pipelines would complicate the existing testing capacity issue and likely make it\ndifficult for any of the testing requirements to be met.\nThe natural gas pipeline network supplies gas for use in real time. This is not the case for\nhazardous liquid pipelines, which move product in batches and have significant storage capacity.\nAssessment of natural gas pipelines can therefore result in inkmptions of gas supply. This can\nhave a safety impact, in addition to its economic effect, due to the need to restart gas service in a\ncontrolled manner so as to avoid explosions at the point of service. Another difference fiom\nhazardous - liquid pipelines _ _ _ is that _ _ significant environmental _ _ _ _ - damage - is not expected - to - result _ _ fiom -\n-- - - -\nfailure of a n a d gas pipeline, since gas islighter than air and theatmosphere.\nThe OPS evaluated the effect on costs to operators of requiring assessments at increased intervals,\nas described later in this analysis. Costs would increase significantly without addition of\ncommensurate benefits.\nFor these reasons, the OPS 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 fust to ascertain the\ncurrent level of activity in areas addressed by the rule. In this instance, it is necessary to\ndetermine the rate at which pipeline inspections are being performed, and the prevalence and\nnature of integrity management plans similar to those required by the rule.\n5\n\n<<<PAGE 7>>>\n\nThe OPS 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 the proposed rule, and has been adopted as a consensus\nstandard. As a result of these interactions, the OPS understands that many gas pipeline operators\ncurrently have integrity management programs including many aspects that would be required by\nthis 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 inspe'ction 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\nmore comprehensive and integrated approaches to safety and environmental protection, the OPS\ncreated the Risk Management Demonstration Program, and the System Integrity Inspection Pilot\nProgram. These programs encourage and evaluate operator-developed safety and environmental\nmanagement processes that incorporate operator- and pipeline-specific idormation and data to\nidentify, assess, and address pipeline risks. These programs are helping RSPA's Office of\nPipeline Safety refine its regulatory oversight processes. These processes help to ensure that\npipeline 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 Eailure\ncould have significant consequences.\n~~ - - __ ~ s k M m a g e m e n L D e r m \" t i o n b g r a a n d - t h e System-IntegritgInspectionPih- -~~ _ _\nProgram, the OPS 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 identifL 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 h m many diverse sources to fully 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 h m them,\nsupplement the minimum regulatory requirements established in 49 CFR 192.\nThe System Integrity Inspection Program is focused on developing a more integrity-based\n6\n\n<<<PAGE 8>>>\n\napproach to OPS inspections. Instead of using a “checklist” approach, the OPS is focusing the\ninspection process on an operator’s integrity management processes and activities. Through\nworking with the operator, the OPS is able to understand and influence the methods and\napproaches 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, the OPS has observed how operators examine intemal\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 the OPS 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 SI1 Program is emphasizing how operators evaluate their\nsystem condition and its risks, and use this information to make sound integrity management\ndecisions.\nThe OPS experience in the Risk Management Demonstration Program and the System Integrity\nInspection Program indicates that integrity management programs such as that required by this\nrule have been developed. They are far from universal, however.\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. Then the potential benefits of the rule are\ndiscussed. In the next section the potential costs of the rule are examined. Finally, a discussion of\nthe costs versus the benefits is presented. It should be noted that, unless otherwise specified, all\ndollar values in this report are given in constant 2001 dollars.’ Furthermore, this analysis will\narbitrarily consider only the first twenty years afker the effective date of the final rule. IncludiB - ____.__\nadditional years would not be expected to mate~ally affect the conclusions-of this d y s i s . __ - - ~ - - - - -\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 are expected to be within specified distances of the pipeline. The\ndistances vary depending on the diameter of the pipe and the pressure at which it operates.\nTotal Pireline Mileage\n‘Dollars are converted from nomina1 values to real 200 1 values using the Producer Price Index (PPI), Intermediate\nMaterials, Supplies, and Components. The source of the PPI index numbers is the U.S. Bureau of Statistics Web\npage.\n7\n\n<<<PAGE 9>>>\n\n~\nIn total, there is an estimated 292 thousand miles of regulated natural gas transmission pipelines\nin the US? This rule would not apply to all of this mileage. The proposed rule does not apply to\npipelines operated at a hoop stress of less than 20 percent of specified minimum yield strength\n(SMYS). The OPS has no data on how much of transmission pipeline mileage is operated at these\nlow stresses, but presumes that it is small. The rule also applies to transmission pipelines for\nhydrogen, synthetic gas and other products subject to 49 CFR Part 192 that are not included in the\nnatural gas transmission pipeline totals. Here, again, the OPS does not have data on the total\ntransmission mileage for these other gases. This analysis uses the available natural gas\ntransmission pipeline total mileage, which is considered to be very close to the total pipeline\nmileage potentially afhted by the proposed regulation.\nImuacted Mileage in Hi& Conseauence Areas\nThe proposed regulatory change does not apply to all of this pipeline. Instead, it applies to that\ntransmission pipeline that can affect high consequence areas, as described earlier. A principal\nelement of this definition is pipeline that is in class 3 and 4 areas as dehed in 49 CFR 192.5.\nPipeline operators are presently required to maintain data on the population near their pipeline in\n--8lrder-to-determine_pip?eline_thati~cl_ass 3 or &s 4 areas. This data_is not required - - to -- be\nsubmitted to the OPS. In a 1992 study of instrumented internal inspection devices, the OPS\nconcluded that approximately 7 percent of the total transmission pipeline mileage was located in\nclass 3 or 4 areas3 The definitions of class 3 and class 4 have not changed since that time. While\npopulation growth may have increased the percentage of total transmission pipeline mileage that\nis in those class are-=, the OPS does not expect that such growth would have significantly afSected\nthe overall percentage. The OPS therefore estimates that 7 percent of current natural gas\ntransmission pipeline mileage, or 20,440 miles, is in class 3 or class 4 areas.\nThexe are several factors in the defhition of high consequence areas which could lead to\nadditional mileage being included. These include:\ne the requirement to consider the location of buildings that could house populations of\nlimited mobility,\n0\nthe requirement to consider areas near pipelines where people congregate, and\n0\nthe requirement to expand the radius of consideration to 1000 feet (or possibly more) for\npipelines larger than 30 inches in diameter and operating at pressures greater than 1000\npsig or where calculations of potential impact radius indicate a likelihood that areas\n2Jurisdictional natural gas transmission pipeline mileage (onshore) for 2000. This mileage was obtained fi\" annual\nreports filed by pipeline operators with the OEce of Pipeline Safety. Data available on the OPS web page.\n30ffice of Pipeline Safety, Instrumentedhternal Inspection Devices (A Study Mandated by P.L. 100-561),\nResearch and Special Programs Administration, November 1992, p. C-2.\n8\n\n<<<PAGE 10>>>\n\nbeyond 660 feet from the pipeline would be afYected by an accident.\nThe OPS does not collect data related to these additional factors. The OPS therefore cannot\ndetermine the total amount of additional pipeline mileage (Le., beyond that in class 3 or 4\nlocations) that would be in high consequence areas. For purposes of this analysis, the OPS\nassumes that these additional factors would increase the total transmission pipeline mileage\naffected by the rule by 20 percent, or 4,088 miles. The OPS seeks comments on the\nreasonableness of this assumption.\nThe total gas transmission pipeline mileage in high consequence areas, and thus impacted by the\nrule is thus 24,528 miles, the sum of the amount estimated to be in class 3 and 4 areas and the\namount assumed to be added as a result of other factors in the definition of high consequence\nareas.\nBENEFITS\nThe benefits resulting h m the proposed regulatory change are discussed in this section. Those\nbenefits are expected to result fiom detection of problems that could cause pipeline failures before\nthe failure occurs, thereby averting accidents. The inspection and assessment that would be\nre@iEd%yL-hejiGpKiSEIFis dGi@ed5id&tiibleiiE related to inteihii-con6sion;ejikfiiiiI\ncorrosion, stress corrosion cracking and extemal damage to the pipeline, all of which can result in\npipeline ruptures. Natural gas pipeline accidents usually involve explosions and fire and can\nresult in death, serious injury, and property damage. Preventing accidents will result in reduced\nnumbers of deaths and serious injuries and in reduced property damage. These reductions, then,\nare principal benefits of the proposed rule. The proposed rule will also provide improved\nassurance of pipeline safety, will provide a basis for increased public acceptance of the risks fiom\nnatural gas transmission pipelines, and will provide other, less tangible, benefits. Each of these\ncategories of benefits is discussed below.\nPipeline operators also have strong incentives to ensure the integrity of their pipelines. In\naddition to the positive safety and societal benefits, the lost product and unscheduled downtime\nfor repairs following a major incident can significantly impact the company’s b c i a l\nperformance and its ability to satisfjr customer commitments. Operators cannot afford to have\nthese critical transportation assets out of service for lengthy periods of time in today’s competitive\nbusiness environment. In addition, the damage to the company’s public image and reputation, as\nwell as the legal implications of serious incidents, can pose an even broader and longer term\nnegative impact on the company’s business operations. For these and other reasons, many pipeline\noperators have implemented and are continuing to improve more systematic safety and\nenvironmental management processes, many of which already embody the principles in this\nproposed rule.\n9\n\n<<<PAGE 11>>>\n\nBenefits from reduced death and serious w1uI.r\"\nAccident reports submitted to the OPS during the period 1986 to 2001 identifjr that there were\n1,285 incidents on natural gas transmission pipelines, resulting in 58 fatalities and 2 17 serious\ninjuries. The consequences of future pipeline accidents could differ, and are likely to be more\nsevere, as discussed below. Nevertheless, it is reasonable to use this 1 &year record as an estimate\nof consequences that would be likely to occur without changes in the manner in which pipeline\nsafety is assured. The proposed rule is expected to reduce these consequences, through\nidentification and remediation of the kinds of anomalies that can cause pipeline accidents before\nthose accidents occur. Accidents that may be prevented by the proposed rule should include a\nhigh percentage of those that result in death and serious injury, since the rule is focused on\npipelines in areas which have the largest concentrations of people in the vicinity of the pipeline.\nIt is not possible, however, to estimate precisely how effective the proposed rule will be in\nreducing such accidents. The maximum benefit that could be achieved would be elimination of\naccidents causing death and serious injury. Based on this historical record, the maximum value\nthat could be realized fiom reducing deaths and serious injuries is thus $282.5 million over 16\nyears or $17.65 million per year.\nBenefits fiom reduced ~ r o ~ e r t ~ dam ape\n~ - - - _ _ _ - - __ _____ -\n_ _ _ - _ _ _ _ ~\nThe same accident data base indicates that $284,829,6 17 in property damage occurred as a resuit\nof those 1,285 pipeline incidents. A recent study indicates that this total may be low due to under-\nreporting of accident costs?\nThe study compared accident costs reported to the OPS with other information, including press\nreports and costs reported in operator's post-accident financial filings. The study considered 49\naccidents, of which only four were natural gas pipeline accidents. (Two of these accidents had not\nbeen reported to OPS). The study found that actual costs for accidents involving hazardous liquid\npipelines were three times the amount reported to the OPS. For the limited set of gas pipeline\naccidents considered, costs were under-reported by a factor of 1.62. The OPS believes that a\nlarger study of gas pipeline accidents would show more under-reporting of costs, similar to the\nsituation revealed for hazardous liquid pipelines. For purposes of this analysis, the OPS assumes\nthat costs may have been under-reported for natural gas pipeline accidents by up to a factor of 2.\nThus, the true value of property damage experienced in natural gas transmission pipeline incidents\nover the last 16 years is in the range of $285 to approximately $570 million.\n4With respect to deaths and serious injuries, the following assumptions are made:\nA life is valued at $3 million\nA serious injury is valued at $500 thousand\nThese valuations are standard assumptions currently used in Office of Pipeline Safety and DOT benefidcost\nanalyses.\n'\"Report on the Accuracy of Cost Data from Incident ReporW, General Physics Corporation, December\n2001, unpublished.\n10\n\n<<<PAGE 12>>>\n\nThis range is used in this analysis as representative of the property damages caused by historical\nnatural gas pipeline accidents. As before, the historical record provides a reasonable estimate of\nfuture accident consequences. Again, the proposed rule is expected to reduce the numbex of\naccidents, and thus the amount of property damage that occurs. The extent of such reduction\ncannot be estimated. The maximum benefit that could be achieved if the historical damage is at\nthe upper end of this range and property damage consequences were eliminated by\nimplementation of the proposed rule is $570 million over 16 years, or $35.6 million per year.\nConsequences of Pimline Accidents are Likely to Increase\nUrban areas are rapidly expanding in the United States. Housing starts have increased 57% over\nthe last ten-year period. Increasingly, this brings additional population into the proximity of the\nnatural gas transmission pipelines that serve our urban areas. Rural areas that pipelines may have\npassed through ten years ago are more likely today to be populated, and that likelihood will\nfurther increase over time. Natural gas pipeline accidents that occur in rural areas have limited\nconsequences, particularly in causing deaths and serious injuries. Accidents in urban areas can be\nmuch more severe.\nThe March 23,1994, accident in Edison Township, New Jersey is a case in point. This area was\nalready u r ~ ~ d ~ ~ ~ ~ ~ ~ i a ~ . - R ~ p- - - -\ntransmission Iine resulted in an explosion and fire that destroyed six apartment buildings.\nProperty damage exceeded $25 million. Approximately 1,500 residents were evacuated fiom &e\napartments. Immediate evacuation prevented any deaths, although one resident living\napproximately one mile h m the scene of the accident suffered a fatal heart attack! Had\ncircumstances been only a little different, significant loss of life could have occurred.\nIncreased development makes it likely that the actual consequences of natural gas pipeline\naccidents over the next 16 years, assuming no changes in the regulatory environment, would be\nmore severe than suggested by the historical record. The OPS has not estimated by how much\nthose consequences might increase, because such an estimate would be highly speculative.\nNevertheless, the trend indicates that use of the historical record to estimate the likely\nconsequences of fhture accidents is almost certainly conservative.\nConseauential ImDact of Natural Gas Pipeline Accidents\nThe accident impacts described above are direct effects, i.e., they are caused directly by the\npipeline rupture and resulting explosion and fire. The consequences of natural gas transmission\npipeline accidents often do not stop there. Other impacts include disruption of business activities\nin the immediate area of the accident and possibly in aceas near the accident.\nQationai Transportation Safety Board, Pipeline Accident Report: Texas Jkstern Transmission\nCorporation Natural Gas Pipeline Explosion and Fire Edison, New Jersey March 23, 1994, January 18, 1995, p. v.\n11\n\n<<<PAGE 13>>>\n\nMany communities are served by natural gas distribution companies that receive their product via\nsingle lateral pipelines from a natural gas transmission pipeline (so-called “sole-source laterals”).\nIf an accident occurs on the transmission pipeline that results in interruption of the flow of natural\ngas, service to customers in communities served by sole-source laterals may be cut off. The\ninterruption may be temporary, if gas supply can be restored by valving out the damaged section\nof pipe and re-establishing supply from undamaged portions of the line. Even so, there is both an\neconomic and a safety consequence to such service inten-uptions.\nwhen natural gas service is cut off, pilot valves on gas appliances go out. Service cannot simply\nbe restored, since gas would enter homes and businesses through the open pilot valves, potentially\nbuild to explosive concentrations, and result in fires, explosions and additional collateral damage.\nFor this reason, restoration of natural gas service requires that local distribution companies follow\nlabor-intensive procedures. Representatives of the distribution company must enter each business\nor residence to which service was interrupted. They must close valves to pilot lights. Distribution\nmains and laterals must be purged to eliminate air that may have become entrained. Only then\ncan service be restored. Restoration of service again requires that an employee of the distribution\noperator must enter the premises, reopen pilot light valves, and re-light the pilot lights. This\nprocess can take several days. A recent service outage involved loss of natural gas service to\napproximately 4500 customers. Service was restored in 48 hours, but only by the efforts of 400\nP e r s ~ ~ e f ~ e d ~ y - ~ ~ ~ ~ o G ~ ~ s ~ h u t i Q n ~ ~ m ~ ~ ass ist in the emergency\nrecovery effort. Economic consequences included business interruption for the period of the\noutage, overtime for local operator personnel, and the need for the local operator to house and\nfeed personnel loaned h m other operators to assist.\nThere is a potential that the impact of consequential damages from Service interruptions could\ngrow. Natural gas is currently being used to power many new electrical generating facilities. As\nmore of the nation’s electricity is generated fiom natural gas, the supply of electricity will also\nbecome dependent on reliable, continuous availability of natural gas. It is possible that future\naccidents on major interstak natural gas transmission pipelines in certain areas could result in loss\nof natural gas supply to multiple electrical generating stations. Electricity generators typically\nhave a supply margin to account for the unexpected loss of a generating facility. If too many\ngenerators are lost simultaneously, however, the margin can be overwhelmed and electrical\nblackouts, with their attendant consequences, could result.\nPublic Confidence\nThe most significant benefit of the proposed rule is less tangible. It will provide a basis for\nimproved public confidence in pipeline safety. Public confidence has been shaken as a result of\nseveral recent accidents with sigdicant consequences. These accidents were widely reported by\nnational media, becoming known well beyond the communities in which they occurred. These\nincluded the 1994 pipeline rupture, explosion, and fire at Edison Township, NJ (discussed above),\na June 10,1999, rupture of a hazardous liquid pipeline in Bellingham, WA, with subsequent fire,\nand an August 19,2000, natural gas pipeline rupture, explosion and fire near Carlsbad, NM.\n12\n\n<<<PAGE 14>>>\n\nThree persons were killed in the Bellingham accident. Twelve persons were killed in the Carlsbad\naccident. (Hazardous liquid pipelines, such as the one involved in the Bellingham accident,\nwould not be affected by this proposed rule. They are covered by similar rules for hazardous\nliquid pipelines, which have already become effective.)\nImproving public confidence is, in itself, important. It will, however, also result in economic\nbenefits.\nOne way in which public concern regarding pipeline safety manifests itself is in increased public\nopposition to new pipelines. Local governments can impose additional requirements and\nrestrictions that delay construction and result in significant additional costs. A recent example\ninvolved the conversion of an existing hazardous liquid pipeline in Texas. Community reaction in\nthe city of Austin resulted in delays and si+cant additional costs. In response to the\ncommunity reaction, the operator replaced 12 miles of the existing pipeline with 2 1 miles that\nlooped to the south of the city, avoiding most populated areas. This significantly increased the\ncost of the pipeline project. The average installed cost of natural gas transmission pipelines\napproved by the Federal Energy Regulatory Commission (FERC) in Fiscal Year 2001 was $2.7\nmillion per d e . ' A similar re-route for a natural gas transmission pipehe thus would have cost\napprE@mtely $56.7 million, - ~-\n- ~ - -~ ~ - - ~ _ ~ _\n~ -____\nIncreased public opposition can also result in delays in implementing pipeline projects. In some\ncases, the related costs associated with responding to public concerns, participation in public\nhearings, and financing of major construction projects during delays can be as significant as, or\nmore than, the cost of installing new pipeline. In the eKtrerne, increasing public concern could\nmake it impossible to site and construct new natural gas transmission pipelines.\nThe United States needs additional natural gas transmission pipeline capacity to meet current and\nfuture needs. FERC approved 2,449 miles of new transmission pipeline in 2001 .8 If operators are\nunable to construct new pipelines, the existing pipeline system would rapidly reach its capacity\nlimit. New applications of natural gas as a fuel would need to be foregone. The ability to use\n~ t ~ r a l gas as an environmentally-preferable fie1 for new electric generating capacity would be\nlost. Curtailment of existing natural gas usage would likely be required. For all of these reasons,\nit is vitally important that the public have confidence that the national network of natural gas\ntransmission pipelines a","truncated":true,"body_characters":123324}