# U.S. DOT/RSPA - Draft Final Regulatory Evaluation - **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:** Not available - **effective on:** Not available - **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:** <<>> 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 <<>> INTRODUCTION The U.S. Department of Transportation Research and Special Programs Office of Pipeline Safety (RSPNOPS) is changing pipeline safety regulations to require operators of certain pipelines to validate the integrity of their pipelines in high consequence areas. The rule applies to operators of natural and other gas transmission pipelines. The objective of the change is to reduce the risk of pipeline incidents in these areas. High consequence areas are redefined in this rule. Under the redefinition, operators must choose one of two options to designate high consequence areas: A11 class 3 & 4 locations (these are areas where there are at least 46 buildings intended for human occupancy or where buildings with four or more stories above ground are prevalent within 660 feet of the pipeline along any continuous mile of its length) plus areas where a potential impact circle of radius greater than 660 feet includes 20 or more buildings intended for human occupancy, or Locations where the potential impact circle, of whatever size, includes 20 or more buildings intended for human occupancy. Under either option, pipeline operators must also include as high consequence areas any potential impact circle that contains: 8 A hospital, school, prison, day care center or other facility having persons who are confined or of limited mobility, or Outdoor locations or open structures where 20 or more persons congregate at least 50 days in any 12-month period, or 0 A building in which 20 or more persons gather 5 days a week for 10 weeks in any 12- month period (the days and weeks need not be consecutive). The potential impact circle used in any of these determinations is a circle, centered on the pipeline, of a radius calculated based on the size and pressure of the pipeline. The potential impact circle approximates the area that could be affected by a rupture and subsequent explosion occurring on the pipeline. To validate the integrity of their pipelines in high consequence areas under the regulatory change, pipeline operators must implement an integrity management program for such pipelines including periodic inspection and testing and integration of information related to pipeline integrity. The purpose of this report is to assess the benefits and costs of the regulatory change. This rule is similar to rules promulgated earlier for hazardous liquid pipeline operators. High consequence areas were defined differently for hazardous liquid pipelines, because the 1 . * . <<>> environmental consequences of leaks from hazardous liquid pipelines are different than those from natural gas pipelines. The elements of an integrity management program required by this rule are similar, however, to the elements previously required of hazardous liquid pipeline operators. This report considers the costs and benefits of these requirements in a manner similar to the analysis of costs and benefits prepared for the earlier rulemakings. TARGET PROBLEM Natural and other gas pipeline breaks can result in explosions and fires that can impact on human health and safety. The magnitude of this impact differs. There are some areas in which the impact of a pipe break will be more significant than it would be in others due to concentrations of people near the pipeline and who thus could be affected. Because of the potential for dire consequences of pipeline failures in certain areas, these areas merit a higher level of protection. The OPS is promulgating this regulation to afford the necessary additional protection to these “high consequence areas”. Numerous investigations by RSPNOPS and the National Transportation Safety Board (NTSB) have highlighted the importance of protecting the public from pipeline failures. The NTSB has made several recommendations to ensure the integrity of pipelines near populated areas. These recommendations included requiring periodic testing and inspection to identify corrosion and other damage, establishing criteria to determine appropriate intervals for inspections and tests, and determining hazards to public safety from electric resistance welded pipe. Congress also directed RSPNOPS to undertake additional safety measures in areas that are densely populated. These statutory requirements included having RSPNOPS prescribe standards for identifjmg pipelines in high density population areas and issue standards requiring periodic inspections using internal inspection devices on pipelines in densely-populated areas. This rulemaking addresses the target problem described above, and is a comprehensive response to the NTSB’s recommendations and Congressional mandates, as well as pipeline safety and environmental issues raised over the years. ALTERNATIVES CONSIDERED The OPS considered several alternatives to provide the necessary increased level of protection to high consequence areas. These alternatives were: 1. No action. 2. Publishing a rule that would adopt requirements of the Pipeline Safety Improvement Act of 2002 and establish procedures to seek waiver of reassessment intervals 3. Prescriptive requirements for inspection and repair of pipelines in high consequence areas. 4. Requiring pipeline operators to develop integrity management programs providing for inspection and testing based on risk factors and integration of information related to pipeline risk. 2 <<>> 5 . Requiring pipeline operators to develop integrity management programs providing for expedited inspection and testing. INITIAL SCREENING OF ALTERNATIVES 1 . No action. Regulatory analyses typically consider an alternative in which the agency would not take any action, because it would maintain the status quo. No new requirements would be levied. No costs would be incurred to implement new requirements. No new benefits would result. In this case, however, the “no action” alternative does not maintain the status quo. The status quo has been changed by Act of Congress. The Pipeline Safety Improvement Act of 2002 (PSIA-2002), signed into law on December 17, 2002, imposes requirements directly on pipeline operators. To be sure, PSIA-2002 directs the Secretary of Transportation to publish, within one year, standards for integrity management plans that would require periodic assessment of pipelines in high consequence areas. PSIA-2002 goes on to require that operators of gas transmission pipelines, regardless of whether or not the Secretary publishes such standards, must conduct a risk analysis, implement integrity management programs, and begin baseline assessments of their pipeline facilities in high consequence areas within 18 months. Baseline assessments must be completed on all gas transmission pipeline segments in high consequence areas within 10 years. Each ‘gas transmission pipeline segment in a high consequence area must be reassessed at least every 7 years. The assessment requirements in PSIA-2002 apply to “each of the operator’s facilities in areas identified pursuant to subsection (a)( 1) [of 49 U.S.C. 0 601 091 and defined in chapter 192 of title 49, Code of Federal Regulations, including any subsequent modifications” (emphasis added)’. The cited provision of the U.S. Code is the legislative requirement that the DOT establish criteria for identifying pipelines in high-density population areas, or high consequence areas. The reference to the definition in title 49 of the Code of Federal Regulations is thus a reference to the definition of high consequence areas established by DOT. The applicability of the Act’s requirements to any “subsequent modifications” of that definition allows the DOT to revise its criteria and further focus the actions required of pipeline operators. Absent a change to the definition embodied in part 192, however, operators would be required to conduct assessments of all pipeline segments meeting the current definition. RSPNOPS, in fact, has been considering changes to the definition of high consequence areas in part 192 to further refine the criteria and to focus better on areas most at risk and for which special requirements are appropriate. Making those changes would reduce the amount of pipeline on which integrity assessments are required to be performed without significantly reducing the ‘Pipeline Safety Improvement Act of 2002, Section 14, “Risk Analysis and Integrity Management Programs for Gas Pipelines” 3 <<>> benefits to be realized from those assessments. PSIA-2002 requires that the pipeline assessments specified in the Act must be conducted using in- line inspection, pressure testing, or direct assessment. The Act also allows assessments to be conducted using “an alternative method that the Secretary [of Transportation] determines would provide an equal or greater level of safety”.’ Here, again, RSPNOPS has been considering additional methods for conducting assessments. Confirmatory Direct Assessment (CDA) was discussed in the proposed rule for integrity management in gas transmission pipelines.’ This method allows for assessment of pipeline integrity at less cost to operators and resulting in less potential interruption in pipeline operations. In addition, RSPNOPS has been considering alternative methods of assessing low-pressure pipeline, for which pipe wall stresses are much lower and failure by leakage is much more likely than ruptures, which would also provide assurance of integrity at less cost than the methods specified in PSIA-2002. Taking no action would leave the definition of high consequence areas in part 192 unchanged. It would also mean that no alternative method, other than those specified in PSIA-2002, could be defined for conducting assessments of gas transmission pipelines in high consequence areas. The result would be conduct of assessments on more pipeline than is needed to address the underlying safety issue using more expensive assessment methods. RSPNOPS evaluated the costs operators would incur under this alternative, as described in the appendix to this analysis, and found that they would be significantly higher than those that would result from other alternatives. In addition, taking no action would not be responsive to the requirement in PSIA-2002 that DOT “issue regulations prescribing standards to direct an operator’s conduct of a risk analysis and adoption and implementation of an integrity management program.’* , ’ For these reasons, the “no action” alternative was not considered further. 2. Publishing a rule that would adopt requirements of the Pipeline Safety Improvement Act of 2002 and establish procedures to seek waiver of reassessment intervals PSIA-2002 allows the Secretary of Transportation to waive or modi@ requirements for reassessments for reasons that may include the need to maintain local product supply or the lack of internal inspection devices, provided that such a waiver is not inconsistent with pipeline safety. Another alternative would be to publish a rule that adopts the substantive requirements of PSLA- 2002, without change, but establishes procedures for approving the allowed waivers. ’bid. ’Federal Register, January 28,2003 (68 FR 4278), “49 CFR 192, Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines); Proposed Rule”. ‘hpeline Safety Improvement Act of 2002, Section 14, “Risk Analysis and Integrity Management Programs for Gas Pipelines” 4 <<>> 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 unnecessary expense for assessments, using the most costly methods to address more pipeline than RSPNOPS has determined is necessary to address the underlying safety need. For this reason, the option of publishing a rule that only establishes procedures for waivers was not evaluated further. 3. Prescriptive requirements for inspection and repair of pipelines in high consequence areas and for incorporating accident mitigative features. Pipeline circumstances differ, even within high consequence areas. These differences would make it difficult, at best, to establish prescriptive requirements that would appropriately address all possible combinations of pipeline size, type, and configuration or to consider other factors that contribute to the risk of failure of a particular pipeline. It is likely that creating detailed prescriptive requirements would result in a need for a large number of waivers to address the issues of importance to specific pipelines and high consequence areas. The result would be a patchwork of specific, but different requirements. It would be an ineficient use of industry and government resources to establish requirements in this fashion. Prescriptive requirements also would tend to stifle technological innovation. They do not allow 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. Establishhg prescriptive requirements could slow this advancement, or could preclude use of new techniques that may be developed. In the extreme, prescriptive requirements could stop technological innovation in this area completely. Establishing prescriptive requirements would not assure the integration of information, which experience has shown is vital to preventing pipeline accidents. Two major pipeline accidents have occurred in recent years despite the fact that information about the causative factors should have, or could have, been known - at Edison Township, NJ and Carlsbad, NM. In the first case, in-line inspection (pigging) of the pipeline had taken place. The operator either failed to identify, during the pig runs, the areas of damage that eventually caused the rupture or the damage occurred in the years following the inspection. In addition, the operator failed to integrate information about the pipeline, including the presence of significant construction activity in the area, in a continuing assessment of the line’s integrity. In the latter case, the accident resulted from internal corrosion due to collection of moisture in a low spot which could not be inspected by pigging. The operator failed to consider the possibility of such accumulation of moisture and resulting corrosion and thus did not intercede to prevent the pipeline failure. It appears that information was available that, if correlated to current pig results (in the case of Edison Township) or other information about the pipeline, could have highlighted the need for action regarding the problems 5 8 <<>> , that ultimately resulted in failure of the pipe. An integrity management program is required to assure this integration of available information. Outside review of the integrity management program by regulators (Federal and state), is necessary to assure that it is complete and properly implemented. This outside review cannot be assured without a requirement for such a program that establishes the requirements against which such a review will be conducted. Most importantly, establishing prescriptive requirements would not be consistent with requirements imposed by PSIA-2002. The Act requires that DOT prescribe rules to direct an operator’s conduct of a risk assessment and adoption and implementation of an integrity management program. Prescriptively establishing when and where integrity assessments must be performed would be inconsistent with the requirements of the Act. For these reasons, the option of establishing prescriptive requirements was not evaluated further. 4. Requiring pipeline operators to develop integrity management programs providing for inspection and testing based on risk factors and integration of information related to pipeline risk. Pipeline operators are uniquely qualified to develop integrity management programs and provide for the necessary integration of information. They have the best knowledge of their pipelines and the factors affecting its risk. Integration of information requires that the management systems of the company be aligned and operated to assure that necessary information is shared and that it is evaluated in its proper context by knowledgeable personnel. These are actions that are difficult to require through prescriptive regulation. Requiring that operators develop such programs is the best way to assure that they occur. Such a requirement also provides the regulatory basis for RSPNOPS and states to audit, review, and assess these programs and their implementation. The best integrity management plans, when implemented properly, can reduce the risk of pipeline accidents. They cannot, however, eliminate that risk. Leaks and ruptures could still occur, from unforeseen outside impacts on the pipeline or from unanticipated interactions among factors contributing to pipeline risk. It is therefore important that features and procedures be available to mitigate the effects of accidents that may occur. Here again, circumstances differ between pipelines and between regions and local jurisdictions. The differences make it difficult to establish prescriptive requirements that will provide the best protection for each high consequence area. Requiring that operators explicitly consider the need for mitigative features and provisions and that they implement those found necessary is the most effective means of providing such protection. Such a requirement also provides the regulatory basis for audit and review by RSPNOPS and state regulators. Establishing requirements for operators to develop and adopt integrity management programs is also most consistent with the requirements imposed on DOT by PSIA-2002. This option also 6 <<>> allows RSPNOPS to make changes in the definition of high consequence areas to improve the ' focus of the new requirements, and to establish altemative methods that are acceptable for, performing integrity assessments. Both of these changes will reduce the costs imposed on industry without significantly reducing the benefits to be realized. For these reasons, this option was selected for further development. 5. Requiring pipeline operators to develop integrity management programs providing for expedited inspection and retesting. RSPNOPS considered the need for requiring integrity management programs that would require inspection and testing of pipelines to recur over short intervals, e.g., a few years. The ability to require frequent testing is limited by the available resources for testing and inspection. The companion rule covering hazardous liquid pipelines requires reassessments at least every five years, with limited exceptions. The current capacity to perform pipeline inspections will be challenged by this required schedule. The OPS concluded that the spur provided by the regulation would be likely to result in an increase in testing capacity over the next five years that will then be able to accommodate testing at accelerated rates. The OPS also concluded that protection from environmental damage that can be caused by a leak or rupture of a hazardous liquid pipeline, and the occurrence in hazardous liquid pipelines of frequent pressure cycles that can cause defects to grow, necessitated such frequent inspection. Adding requirements for similarly frequent inspection of natural gas pipelines would complicate the existing testing capacity issue and likely make it difficult for any of the testing requirements to be met. , ' Existing regulations already provide some additional protection from accidents on gas transmission pipelines that could affect high consequence areas.' The requirements of 49 CFR 192.61 1 specify that pipelines in class 3 or 4 areas must operate at pressures that produce significantly lower hoop stresses in the pipe than is allowed in more rural areas. As a practical matter, operators meet this requirement by reducing operating pressure or using heavier-walled pipe in class 3 and 4 areas. Hazardous liquid pipelines do not afford similar protection in high consequence areas. The additional protection already provided by natural gas transmission pipelines justifies assessment on a more extended interval than for hazardous liquid pipelines. Additionally, the natural gas pipeline network supplies gas for use in real time. This is not the case for hazardous liquid pipelines, which move product in batches and have significant storage capacity. Assessment of natural gas pipelines can therefore result in interruptions of gas supply. This can have a safety impact, in addition to its economic effect, due to the need to restart gas service in a controlled manner so as to avoid explosions at the point of service. The likelihood of service interruptions, with attendant costs and safety concerns, increases as the assessment interval is shortened, since operators have less flexibility to conduct assessments at times when demand is lower. 7 <<>> Finally, significant environmental damage is not expected to result from failure of a natural gas pipeline, unlike hazardous liquid pipelines, since gas is lighter than air and dissipates in the ’ atmosphere. The PSIA-2002 requires reassessments on no greater than 7-year intervals. This altemative would be similar to the “no rule” option in that it would require assessments using in-line inspection, pressure testing, or direct assessment at no more than seven year intervals. The OPS has established requirements in this rule that would provide for a more focused assessment on this shorter interval, to reduce the likelihood of supply interruptions. As described above and in the appendix, RSPNOPS has evaluated the costs of options that do not allow the revised scope for 7- year inspections. Costs would increase significantly without addition of commensurate benefits. For these reasons, RSPNOPS concluded that assessment of natural gas pipelines need not be required as frequently as for hazardous liquid pipelines. BASELINE REGULATORY ENVIRONMENT In order to assess the costs and benefits of the new regulation, it is necessary first to ascertain the current level of activity in areas addressed by the rule. As described above, legislation recently enacted will impose a change in this level of activity, requiring the implementation of integrity management plans and conduct of integrity assessments that have not previously been performed. Still, it is necessary to determine the level of activity that has been occurring. The costs, and benefits, of implementing either this rule, or the requirements of PSIA-2002 without a rule, must be measured against this historical background. In this instance, it is necessary to determine the’ rate at which pipeline inspections are being performed, and the prevalence and nature of integrity management plans similar to those required by the rule. RSPNOPS has interacted with gas pipeline operators in recent years as part of development of an integrity management standard by the American Society of Mechanical Engineers (ASME). The standard includes many of the elements of this rule, and has been adopted as a consensus standard. As a result of these interactions, RSPNOPS understands that some gas pipeline operators currently have, or are developing, integrity management programs including many aspects required by this regulation. These current integrity management programs include inspection of their pipelines by some operators. The amount of such inspection is relatively low, however. Much of the testing being conducted by these operators is the initial inspection of pipelines. The rate at which subsequent inspections would be performed is now unknown. It is likely that some pipeline would be identified for reinspection routinely (e.g., every ten years). It is equally likely that some pipeline would not be reinspected at all. Integrity management plans are a key element of this rule. To better understand and promote 8 <<>> more comprehensive and integrated approaches to safety and environmental protection, RSPNOPS created the Risk Management Demonstration Program, and the System Integrity Inspection Pilot Program. These programs encourage and evaluate operator-developed safety and environmental management processes that incorporate operator- and pipeline-specific information and data to identify, assess, and address pipeline risks. These programs are helping RSPA’s Office of Pipeline Safety refine its regulatory oversight processes. These processes help to ensure that pipeline operators have effective processes in place to identify the most important risks to the public and the environment, and to develop and implement cost-effective preventive and mitigative actions to manage these risks. Many of these initiatives have validated the importance of focusing resources and establishing higher levels of protection in areas where a pipeline failure could have significant consequences. Through the Risk Management Demonstration Program and the System Integrity Inspection Pilot Program, RSPNOPS has improved its understanding of pipeline operator integrity management systems and activities. This experience has shown that a number of pipeline operators have formalized management systems to identify and address the most significant integrity threats to their pipeline systems. In the Risk Management Program, participants perform systematic and comprehensive risk assessments to identify the specific nature and location of the most significant risks posed by operation of their pipeline system. An essential feature of these risk assessments is the integration of information from many diverse sources to hlly understand the integrity threats at specific locations on the pipeline. The impact on nearby population is explicitly considered in these risk assessments. Through formal, risk-based decision making processes, these companies use the risk assessment results to identify projects and activities that address potential system integrity threats, thereby preventing leaks and accidents. These investigative risk management programs, and the preventive and mitigative risk control activities that evolve from them, supplement the minimum regulatory requirements established in 49 CFR 192. The System Integrity Inspection Program is focused on developing a more integrity-based approach to RSPNOPS inspections. Instead of using a “checklist” approach, RSPNOPS is focusing the inspection process on an operator’s integrity management processes and activities. Through working with the operator, RSPNOPS is able to understand and influence the methods and approaches used to assess pipeline integrity, and the approaches to integrating integrity assessment data with other pipeline specific information, to identify the most significant integrity threats to the system. Specifically, RSPNOPS has observed how operators examine internal inspection data in conjunction with other surveillance and operating data, expected population growth, land use, construction activity along the pipeline, and other information relevant to assuring the integrity of the pipeline in high population areas and in environmentally sensitive areas. Through this interaction RSPNOPS is acquiring a broader understanding and a greater confidence that effective programs are in place to address the most significant risks. Similar to the Risk Management Program, the SII Program is emphasizing how operators evaluate their system condition and its risks, and use this information to make sound integrity management decisions. 9 <<>> The RSPNOPS experience in the Risk Management Demonstration Program and the System Integrity Inspection Program indicates that integrity management programs including many of the elements required by this rule have been developed. They are far from universal, however. CONSIDERATION OF PUBLIC COMMENTS A number of comments were received in response to the proposed rule (68 FR 4278) and the regulatory analysis supporting it (referred to herein as the draft regulatory analysis). Comments from industry generally agreed that the earlier analysis had significantly underestimated the costs of complying with the proposed rule. The Interstate Natural Gas Association of America (INGAA) and the American Gas Association (AGA) made specific recommendations for changes to the proposed rule. In each case, the associations provided estimates of the costs, and savings, that would result from their changes. RSPNOPS acknowledges that the earlier regulatory analysis underestimated the costs of complying with the proposed rule. There were two principal reasons for this understatement. First, RSPNOPS used outdated information for estimating the costs of performing modifications on pipelines (e.g., to accommodate in-line inspection devices) and to perform inspections. The RSPNOPS estimates were based on studies that were performed in the early 1990s. Costs had been escalated to 2001 using the producer price index (i.e., to reflect inflation). Changes since 1990 in how this work must be performed, particularly costs associated with complying with improved environmental standards, significantly outpaced inflation during this period. RSPNOPS acknowledges this deficiency. For this analysis, RSPNOPS has adopted the unit costs (i.e., costs per mile or costs per company) used by INGAA and AGA in their analyses, as described herein for individual cost elements. The unit costs used by INGAA and AGA in their cost estimates differ. AGA explains the reason for this difference as the higher costs to do any kind of work, particularly work requiring excavation, in the urban environment in which its members operate. RSPNOPS acknowledges that costs are likely higher for urban work, and agrees that use of different unit costs for companies in such areas is reasonable. RSPNOPS has restructured this analysis to estimate costs separately for companies operating long-distance transmission pipelines in mostly rural areas (similar to INGAA members) and those operating transmission pipelines in urban areas (similar to AGA members). Unit costs derived from INGAA comments have been used for the long-distance estimates, and those from AGA’s comments are used to estimate costs for companies in urban environments. (RSPNOPS has also updated the estimated costs associated with the proposed rule, using the new unit costs. These estimates are provided in the appendix, in order to illustrate the effect on costs of changes made between the proposed rule and the final rule). Second, RSPNOPS used a much lower estimate for the amount of “overtesting” that will occur than used by INGAA in its analysis. Overtesting refers to pipeline not in high consequence areas that must be tested in order to test segments of pipeline that are within those areas. This 10 <<>> principally affects in-line inspection (i.e., pigging). Inspection tools (i.e., pigs) must be inserted into the pipeline, run over the length of pipe to be inspected, and removed. Insertion and removal must occur at locations where there are launchers and receivers, structures attached to the pipeline which allow for insertion and removal of these large tools. RSPNOPS's preliminary draft regulatory analysis in support of the proposed rule had estimated the amount of overtesting as 25 percent (i.e., for every 10 high consequence area miles tested, 12.5 total miles would be tested). The Technical Pipeline Safety Standards Committee recommended that this assumption be increased when it reviewed the preliminary draft regulatory analysis. That analysis was' changed to assume 200 percent overtesting. , The comments submitted by INGAA and AGA used different estimates for overtesting. AGA assumed 100 percent overtesting for pigging, and no overtesting for pressure testing or direct assessment. This reflects that a significant portion of the transmission pipeline mileage of AGA members is likely to be in high consequence areas and that the distance between pig launchers and receivers in urban areas is relatively short. INGAA did not report a percentage assumption for overtesting. Instead, INGAA surveyed its members to obtain an estimate of the number of miles that they believed would be classified as high consequence areas and the number of miles that would have to be tested in order to pig those segments. The total number of miles that would be inspected was reported to be 7.25 times the estimated length of the high consequence area segments. RSPNOPS finds that this factor, while considerably higher than the 200 percent overtesting assumed in the draft analysis, is reasonable. High consequence areas are likely to be widely dispersed on long-distance transmission pipelines. The distance between pig launchers and receivers on those pipelines is relatively long, on the order of 50 miles. The combination of these factors makes it likely that a significant amount of overtesting will occur on these pipelines. RSPNOPS has adopted, for purposes of this analysis, an assumption of 625 percent overtesting, for pigging, consistent with the results of the INGAA survey. INGAA assumed 25 percent overtesting for pressure testing, which is the same factor RSPNOPS uses in this analysis. There is no overtesting required for assessments performed by direct assessment. INGAA also commented that the draft regulatory analysis underestimated the costs associated with data integration. The draft analysis had assumed that this would cost $100,000 in the first year for each company operating more than 40 miles of transmission pipeline and $50,000 annually thereafter. (The corresponding numbers for operators with fewer transmission miles were $25,000 and $12,500 respectively). INGAA agreed that more costs would be incurred in the first year, when record systems must be realigned and older records, many in paper form, must be converted for later analysis. INGAA estimated that the costs to perform this work would be $1,359 per mile in the first year, and $1 13 per mile annually thereafter. RSPNOPS agrees that estimating these costs on a per-mile basis (as opposed to per-company) is more reasonable, since the number of records that must be considered is proportional to the amount of pipeline an operator has. RSPNOPS also accepts that the costs for retrieval and conversion of older, paper records is likely to be high. RSPNOPS has adopted the INGAA per-mile estimates for estimating the cost of data integration. 11 <<>> Commenters also addressed the benefits of the proposed rule. Carol Parker noted that the Carlsbad accident had a significant economic impact on the state of California due to reductions in gas delivery following the accident. Ms. Parker suggested that avoiding future economic impacts of this type is a benefit reasonably attributable to this rule. RSPNOPS agrees. RSPNOPS has estimated the magnitude of the economic impact that the Carlsbad accident had on California and describes that in this analysis among the benefits of the final rule. REVIEW BY TECHNICAL PIPELINE SAFETY STANDARDS COMMITTEE The OPS presented a preliminary draft of this regulatory analysis to the Technical Pipeline Safety Standards Committee (TPSSC) at a public meeting (conducted by teleconference) on July 3 1, 2003. TPSSC is a Federal advisory committee charged with responsibility for advising on the technical feasibility, reasonableness, cost-effectiveness, and practicability of gas pipeline safety standards. The TPSSC, by law, serves as the peer reviewer for RSPNOPS regulatory analyses. The TPSSC noted that the provisions of PSIA-2002 impose restrictions that make it difficult to optimize the costs and benefits of the rule. In particular, the Act requires that pipeline segments in high consequence areas be subjected to baseline assessments within 10 years and be reassessed every seven years. This has two effects. 0 It results in an “overlap” period in the eighth, ninth, and tenth years after the law was enacted, in which both baseline and reassessments will be performed. The increased level of testing in these years increases costs and increases the likelihood that pipelines being taken out of service for assessment will result in curtailment of gas supply It requires pipelines to be inspected more frequently than is likely needed, particularly for pipelines operating at low stress levels. The TPSSC acknowledged that RSPNOPS had done as much as possible, within the restrictions of the Act, to minimize the effect of these restrictions. The committee unanimously found that the cost-benefit analysis supported going forward with the final rule. SCOPE AND PARAMETERS OF ANALYSIS This analysis of benefits and costs takes the following approach. First, the mileage impacted by the regulatory change is identified and estimated. Mileage is estimated separately for long- distance transmission pipeline operators (representative of INGAA members) and for local distribution companies (LDC, representative of AGA members). Then the potential benefits of the rule are discussed. In the next section the potential costs of the rule are examined. Costs are estimated separately for long-distance operators and LDCs, due to the differences in unit costs for work done by each class of operator (as discussed above). Finally, a discussion of the costs versus the benefits is presented. It should be noted that, unless otherwise specified, all dollar values in 12 ‘ 1 . <<>> this report are given in constant 2001 dollars.' Furthermore, this analysis will arbitrarily consider only the first twenty years after the effective date of the final rule. Including additional years would not be expected to materially affect the conclusions of this analysis. ANALYSIS Impacted Mileage In this section the total pipeline mileage impacted by the regulatory change is estimated. That mileage is located in or nearby high consequence areas, defined by the change as areas in which defined numbers of people or facilities housing people of limited mobility are within specified distances of the pipeline. The distances vary depending on the diameter of the pipe and the pressure at which it operates. Total Pipeline Mileage In total, there is an estimated 285 tilousand miles of regulated onshore natural gas transmission pipelines in the U.S.6 This rule would not apply to all of this mileage. The principal requirements of the final rule apply to pipeline mileage in high consequence areas, which is estimated below. The rule also applies to transmission pipelines for hydrogen, synthetic gas and other products subject to 49 CFR Part 192 that are not included in the natural gas transmission pipeline totals. RSPNOPS does not have data on the total transmission mileage for these other gases. This analysis uses the available natural gas transmission pipeline total mileage, which is considered to be very close to the total pipeline mileage potentially affected by the regulation. Impacted MileaEe in High Consequence Areas The major elements of the regulatory change apply to that transmission pipeline that is in high consequence areas. The rule provides two options for an operator to determine whether a segment of pipeline is in a high consequence area. Under option a, all pipeline in class 3 and 4 areas, as defined in 49 CFR 192.5, would be included, as well as additional pipeline having an identified site within a potential impact circle. Under option b, operators would determine what pipe is in high consequence areas by evaluating potential impact circles along the entire pipeline. 'Dol - **truncated:** true - **body characters:** 206512