U.S. DOT/RSPA - Final Regulatory Evaluation

Page 1U.S. Department of Transportation Research and Special Programs Administration Final Regulatory Evaluation Pipeline Integrity Management in High Consequence Areas (Hazardous Liquid Pipeline Operators with less than 500 miles of Pipelines) Docket RSPA-00-7408#

Page 2INTRODUCTION The U.S. Department of Transportation Research and Special Programs Office of Pipeline Safety (OPS) is changing pipeline safety regulations to require operators of certain hazardous liquid pipelines to validate the integrity of their pipelines in high consequence areas (HCAs). The rile would apply to operators with less than 500 aggregate miles of pipeline. (Requirements for operators with more than 500 miles of hazardous liquid pipeline were established in a previoi is rulemaking). The objective of the change is to reduce the risk of hazardous liquid pipeline incidents in these areas. OPS defines a high consequence area as one in which there is a high population area or densely populated area, a commercially navigable waterway, or an unusua ly sensitive area. To validate the integrity of their pipelines in high consequence areas under thi : regulatory change, pipeline operators must implement an integrity management program for : uch 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 regulatc ~ r y change. TARGET PROBLEM Hazardous liquid pipeline spills can have an adverse impact on human health and the environment. The magnitude of this impact differs. There are some areas in which the impa :t of a spill will be more significant than it would be in others due to concentrations of people whc I could be affected or to the presence of environmental resources that are unusually sensitive tc 1 damage. Because of the potential for dire consequences of pipeline failures in certain areas, these areas merit a higher level of protection. OPS is promulgating this regulation to afford the necessary additional protection to these “high consequence areas”. Numerous investigations by OPS and the National Transportation Safety Board (NTSB) havi : highlighted the importance of protecting the public and environmentally sensitive areas fron L pipeline failures. NTSB has made several recommendations to ensure the integrity of pipeliries near populated and environmentally sensitive areas. These recommendations included requi ing periodic testing and inspection to identify corrosion and other damage, establishing criteria ti 1 determine appropriate intervals for inspections and tests, determining hazards to public safet 1 1 fiom electric resistance welded pipe and requiring installation of automatic or remotely-oper ited mainline valves on high-pressure lines to provide for rapid shutdown of failed pipelines. Congress also directed OPS to undertake additional safety measures in areas that are densely populated or unusually sensitive to environmental damage. These statutory requirements included having OPS prescribe standards for identifying pipelines in high density population areas, unusually sensitive environmental areas, and commercially navigable waters; issue standards requiring periodic inspections using internal inspection devices on pipelines in der lsely- populated and environmentally sensitive areas; and survey and assess the effectiveness of 1#

Page 3emergency flow restricting devices, and prescribe regulations on circumstances where an operator must use the devices. This rulemaking addresses the target problem described above, and is a comprehensive respoi ise to NTSB’s recommendations and Congressional mandates, as well as pipeline safety and environmental issues raised over the years. ALTERNATIVES CONSIDERED OPS considered several alternatives to provide the necessary increased level of protection to 1 iigh consequence areas. These alternatives were: 1. No action. 2. Prescriptive requirements for inspection and repair of pipelines in high consequence areas and for incorporating accident mitigative features and improved leak detection. 3. Requiring pipeline operators to develop integrity management programs providing for inspection and testing based on risk factors and integration of information related to pipeline iisk and to add accident mitigative features and improved leak detection based on risk. 4. Requiring pipeline operators to develop integrity management programs providing for expedited inspection and testing. INITIAL SCREENING OF ALTERNATIVES 1. No action. Pipeline operators currently manage their pipeline to avoid accidents, leaks and spills. They perform inspection and testing on their pipelines to assess their integrity, and make repairs as they conclude they are needed. These actions would be expected to continue under the “no action” a1 ternative. Pipeline leaks, spills, and ruptures occur, despite the existence of these operator programs. Major pipeline spills have occurred in the last two years, of which two were particularly notallle, (Bellingham and PEPCO). In both cases, in-line inspection (pigging) of the pipeline had taki :n place. Operators either failed to recognize the significance of indications from the pig runs or failed to integrate that information with other information about the pipeline, including the presence of construction activity in the area. OPS concludes that validation of these prograrr s through audit and review by outside parties, i.e, the regulator, is necessary to help assure that appropriate actions are taken. In addition, continuation of voluntary programs cannot be assured absent some regulatory requirement. Pipeline operators must be responsive to market conditions, and future change! in economic conditions could lead to curtailment or elimination of some or all inspection and testing. 2#

Page 4OPS concludes that assuring continuation of pipeline integrity management programs, assurir g that their scope encompasses all areas requiring special protection, and verifying their adequa :y are necessary to assure that the requisite level of protection will be provided. This assurance cannot be provided without some regulatory requirement addressing the target problem. In addition, continued reliance on voluntary industry efforts would not be responsive to the Congressional mandate that OPS promulgate requirements to assure protection of the areas th at are herein designated as high consequence areas. For these reasons, the “no action” alternative was not considered further 2. Prescriptive requirements for inspection and repair of pipelines in high consequence areas and for incorporating accident mitigative features and improved leak detection. Pipeline circumstances differ, even within high consequence areas. These differences would make it difficult, at best, to establish prescriptive requirements that would appropriately addri :ss all possible combinations of pipeline size, type, and configuration or to consider other factor: 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 inefficient use of industry 2 nd government resources to establish requirements in this fashion. Compliance inspection woulij still require that the requirements applicable to specific pipelines be identified for comparisoi L with ongoing practices. Prescriptive requirements also would tend to stifle technological innovation. They do not all iw for different approaches based on advances in the technology. The technology associated wi. h 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 techniciues that may be developed. In the extreme, prescriptive requirements could stop technological innovation in this area completely. Most importantly, however, establishing prescriptive requirements would not assure the integration of information which experience has shown is vital to preventing pipeline accidei its. As noted above, two major accidents have occurred in recent years despite the fact that the pipelines involved had been pigged. It appears that other information was available that, if correlated to the pig results, could have highlighted the need for action regarding the indicatilms that ultimately resulted in failure of the pipe. An integrity management program is required o assure this integration of available information. Outside review of the integrity management program (Federal and state) by regulators, is necessary to assure that it is complete and propt rly implemented. This outside review cannot be assured without a requirement for such a progr im. For these reasons, the option of establishing prescriptive requirements was not evaluated fur her. 3#

Page 53. Requiring pipeline operators to develop integrity management programs providing for inspection and testing based on risk factors and integration of information related to pipeline 1 isk and to add accident mitigative features and improved leak detection based on risk. Pipeline operators are uniquely qualified to develop integrity management programs and prov ide 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 system:, of the company be aligned and operated to assure that necessary information is shared and that i. is evaluated in its proper context by knowledgeable personnel. These are actions that are difficii It to require through prescriptive regulation. Requiring that operators develop such programs is the best way to assure that they exist. Such a requirement also provides the regulatory basis for (IPS to audit, review, and assess these programs and their implementation. The best integrity management plans, when implemented properly, can reduce the risk of pipi :line accidents. They cannot, however, eliminate that risk. Leaks and ruptures could still occur, fmm unforseen outside impacts on the pipeline or fkom unanticipated interactions among factors contributing to pipeline risk. It is therefore important that features and procedures be available to detect and mitigate the effects of accidents that may occur. Here again, circumstances differ between pipelines and between regions and local jurisdictioi is. The differences make it difficult to establish prescriptive requirements that will provide the bl:st protection for each high consequence area. Requiring that operators explicitly consider the n :ed for improved leak detection and for mitigative features and provisions and that they impleme it 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 OPS and state regulatclrs. For these reasons, this option was selected for fbrther development. 4. Requiring pipeline operators to develop integrity management programs providing for expedited inspection and retesting. OPS considered the need for requiring integrity management programs that would require inspection and testing of pipelines to recur over short intervals, a few years. The ability to require frequent testing is limited by the available resources for testing and inspection. The companion rule originally proposed for operators with more than 500 miles of pipeline included requirements for reassessment at ten-year intervals. Based upon consideration of comments received, that interval was reduced in the final rule to five years, with limited excpetions. OPS concluded that the spur provided by the regulation would be Iikely to resul. in an increase in testing capacity over the next five years that will then be able to accommodate testing at accelerated rates. OPS considers it important to inspect and test pipeline in high consequence areas at an aggressive rate in order to assure the additional protection desired fclr these areas. OPS concludes that a similar interval is appropriate for operators with less than 500 4#

Page 6miles of pipeline because the increased testing capacity will also be available to them and because their historical testing rate is at a similar fiequency. BASELINE REGULATORY ENVIRONMENT In order to assess the costs and benefits of the new regulation, it is necessary to first ascertain the current level of activity in areas addressed by the rule. In this instance, it is necessary to determine the rate at which pipeline inspections are being performed, the presence of prevent ve and mitigative features, and the prevalence and nature of integrity management plans similar o those required by the rule. Informal discussions with operators with less than 500 miles of pipeline have identified that r iiost have a regular assessment program. A large majority appear to test all of their pipelines on a fi-equency of five years or less. OPS assumes that this rate applies to piping in high conseque nce areas and that this rate would have continued absent a regulatory requirement to increase it. 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 s( )me pipeline would be identified for reinspection frequently (e.g., every five years). It is equally likely that some pipeline would not be reinspected at all. OPS also has limited knowledge about the nature and extent of preventive and mitigative fea ures and procedures that have been implemented by pipeline operators. The mitigative feature fo1 which OPS has the best knowledge is emergency flow restriction devices (EFRDs). EFRDs ,ire check valves or remotely operated valves, usually block valves, that can reduce the amount o F product lost in a pipeline leak. It is estimated that 84.1 percent of all valves currently instal ed on hazardous liquid pipelines are manually operated block valves.’ OPS has no knowledge c f current plans to convert any of these valves to remote operation. Integrity plans are a key element of this rule. To better understand and promote more comprehensive and integrated approaches to safety and environmental protection, OPS creatc :d the Risk Management Demonstration Program, and the System Integrity Inspection (SII) Pilclt Program. These programs encourage and evaluate operator-developed safety and environmeiital management processes that incorporate operator- and pipeline-specific information and data to identify, assess, and address pipeline risks. These programs, along with the Oil Spill Respor se Plan Review and Exercise Program, are helping RSPA’s Office of Pipeline Safety (OPS) ref ne its regulatory oversight processes. These processes help to ensure that pipeline operators ha7 re 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 ‘Office of Pipeline Safety, Emergency Flow Restricting Devices Study (A Study Mandated by P.L. 100-561), U S. DOT, April 1990. The original source of the information was reported to be the American Petroleum Institute. 5#

Page 7manage 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 F ilot Program, OPS has improved its understanding of pipeline operator integrity management syst lems and activities. This experience has shown that a number of liquid pipeline operators have formalized management systems to identify and address the most significant integrity threats o their pipeline systems. In the Risk Management Program, participants perform systematic an1 i 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 risl assessments is the integration of information from many diverse sources to fully understand tl le integrity threats at specific locations on the pipeline. Environmental consequences and the imiDact on nearby population are explicitly considered in these risk assessments. Through formal, rislc- based decision making processes, these companies use the risk assessment results to identify projects and activities that address potential system integrity threats, thereby preventing oil SF ills. The risk management process also examines the consequences of potential releases and explc res opportunities to minimize the environmental and public safety and health impacts should a failure occur. These investigative risk management programs, and the preventive and mitigal ive risk control activities that evolve from them, supplement the minimum regulatory requiremer Its established in 49 CFR 195 to protect the public and the environment. The System Integrity Inspection Program is focused on developing a more integrity-based approach to OPS inspections. Instead of using a “checklist” approach, OPS is focusing the inspection process on an operator’s integrity management processes and activities. Through working with the operator, OPS is able to understand and influence the methods and approac lies 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 systlem. Specifically, OPS has observed how operators examine internal inspection data in conjunctia n with other surveillance and operating data, expected population growth, land use, constructic n activity along the pipeline, and other information relevant to assuring the integrity of the pipt line in high population areas and in environmentally sensitive areas. Through this interaction OP S is acquiring a broader understanding and a greater confidence that effective programs are in pla :e to address the most significant risks. Similar to the Risk Management Program, the SI1 Program is emphasizing how operators evaluate their system condition and its risks, and use this information to make sound integrity management decisions. OPS experience in the Risk Management Demonstration Program and the System Integrity Inspection Program indicates that integrity management programs such as that required by tk is rule have been developed. They are far from universal, however. 6#

Page 8SCOPE AND PARAMETERS OF ANALYSIS This analysis of benefits and costs takes the following approach. First, the mileage impacted iy the regulatory change is identified and estimated. Then the potential benefits of the rule are discussed. In the next section the potential costs of the rule are examined. Finally, a discussicln of the costs versus the benefits is examined. It should be noted that, unless otherwise specific d, all dollar values in this report are given in constant 1998 dollars.2 Furthermore, this analysis 'vi11 arbitrarily consider only the first twenty years after the effective date of the final rule. Includi ng additional years would not be expected to materially affect the conclusions of this analysis. ANALYSIS Impacted Mileage In this section the total hazardous liquid pipeline mileage impacted by the regulatory change i s estimated. That mileage is located in or nearby high consequence area's, defined by the chan 1;e as: (1) high population areas, (2) densely populated areas, (3) commercially navigable waterways, and (4) unusually sensitive areas. Total PiDeline Mileage In total, there is an estimated 157 thousand miles of regulated hazardous liquid pipelines in tlie U.S.3 This change would not impact all hazardous liquid pipeline operators. Rather, it woulc I impact only those operators with an aggregate of less than 500 miles of pipeline. The Office of Pipeline Safety (OPS) estimates that these operators have 13.3 percent of the jurisdictional hazardous liquid pipeline mileage.4 Thus, the operators covered by the rule are expected to h ave about 20,900 miles of regulated hazardous liquid pipelines. Impacted Mileage in High Population And Densely Populated Areas Because of the similar nature of the two types of areas, the impacted pipeline mileages in higln population areas and in densely populated areas are considered together. As defined by the 'Dollars are converted from nominal values to real 1998 values using the Producer Price Index (PPI), Intermed ate Materials, Supplies, and Components. The source of the PPI index numbers is the U.S. Bureau of Statistics Wt b page. 'Jurisdictional hazardous liquid pipeline mileage for 1999. This mileage was obtained from Office of Pipeline Saf: :ty User Fee Assessments. 'This percentage estimate was based on information from Office of Pipeline Safety User Fee Assessments. This estimate may overstate the actual percentage operated by operators with less than 500 miles of pipeline, becaus some operators may report pipeline segments using multiple names. Therefore, some operators with apparent11 little pipeline mileage may actually be part of larger operators. 7#

Page 9regulatory change, a high population area is one with 50,000 or more people in total and at lezist 1,000 people per square mile. A densely populated area is defined as any place containing a concentrated population, such as an incorporated or unincorporated town or village. The OPS estimates that 16,500 miles of regulated hazardous liquid pipeline are located in higli population areas and another 5,500 miles are located in densely populated areas. It is likely tl lat only part of this 22,000 miles is pipeline covered by the rule. Since 13.3 percent of the total mileage is operated by operators with less than 500 miles of pipeline, it appears reasonable to assume, in the absence of contrary information, that 13.3 percent of the mileage located in hii1,h population and densely populated areas, or 2,930 miles of pipeline, is operated by these operators. Impacted Mileage Near Commercially Navigable Waterways The regulated pipeline mileage in or near commercially navigable waterways includes (1) the mileage crossing those waterways and (2) the mileage lying near enough to the waterways to adversely impact them, should a leak, spill, or rupture occur. The OPS estimates that 800 miles of regulated hazardous liquid pipeline are in or near navigilble waterways. It is likely that only part of this mileage is pipeline within the scope of this rulemaking. Since 13.3 percent of the total mileage is operated by operators with less than 500 miles of pipeline, it appears reasonable to assume that 13.3 percent of the mileage in or near navigable waterways, or 1 10 miles of pipeline, is operated by these operators. Impacted Mileage in Unusually Sensitive Areas A pilot test relating to unusually sensitive areas (USAs) was recently conducted by the U.S. Department of Transportation (U.S. DOT) and the American Petroleum Institute (API). This pilot test covered pipelines in California, Louisiana, and Texas. One product from this pilot t:est was an estimate of the jurisdictional pipeline mileage in USAs or that could affect a USA. rl he pilot test results indicate that 14.2 percent of hazardous liquid pipeline mileage in the three s ates is located in a USA. Some of this pipeline was also located in high- or densely-populated ar :as. Pilot program results indicate that 2.7 percent of hazardous liquid pipeline mileage in the thr :e states was in both a USA and a populated area. Thus, 1 1.5 percent of pipeline mileage in thc pilot states was in a USA but not otherwise encompassed within the definition of a high consequence area. For purposes of this analysis, OPS has assumed that the same percentage of hazardous liquid pipeline mileage in other states is located in USAs but not otherwise in a hi gh consequence area. This percentage multiplied by the total hazardous liquid mileage of opere tors with less than 500 miles of pipeline, 20,900 miles, results in an estimate of 2,400 miles for t le pipeline mileage of these operators that is located in USAs. 8#

Page 10Total ImDacted Mileage Given the estimates derived above for the impacted mileage in or nearby high consequence ar :as, a total of 5,440 miles of regulated hazardous liquid pipeline is expected to be impacted by the regulatory change. Mileage Impacted Per Year The regulatory change calls for inspection and testing, improving leak detection where appropriate, and the use of additional prevention or mitigation measures where necessary. Ar example of such a measure includes the installation of Emergency Flow Restricting Devices (EFRDs) at selected points. For the purpose of illustration this analysis examines the potentiill costs of installation of EFRD’s, although EFRD’s are only one alternative among many possi ;)le preventive and mitigative measures that operators could choose. The mileages impacted per year will be important inputs in the calculation of the benefits and costs of inspection and tesl ing and the benefits of the installation of the EFRDs. Inspection and Testing The regulatory change requires baseline and subsequent testing of the impacted mileage usin] ; in- line inspection, pressure testing, or alternative methods. Acceptable in-line inspection includ es high resolution, low resolution, and ultrasonic pigging. Acceptable pressure testing consists )f hydrostatic testing. Acceptable alternative methods include any other methods that would provide a level of safety equivalent to that provided by internal inspection or pressure testing Baseline Testing The rule requires that baseline testing be completed within seven years of the effective date clf the rule. Informal discussions with operators with less than 500 miles of pipeline have identified that most have a regular assessment program. A large majority appear to test all of their pipeline ; on a frequency of five years or less. Thus, it would appear that they would need to test no addit onal mileage beyond that otherwise planned in order to meet the requirements for baseline inspec ion. OPS recognizes, however, that there are probably some companies not already conducting assessments at frequencies consistent with the rule, even though the overall amount of inspe1:tion and assessment in the industry is more than would be required. OPS has conservatively assL med that as much as 10 percent of impacted mileage, or 544 miles, may require unplanned assessinent over a seven year period (78 miles per year). 9#

Page 11Once baseline testing has been performed on a segment of pipe, the rule requires that subsequlmt testing be undertaken on that segment, based on risk factors, at least once every five years (wilh limited exceptions). The planned rate of re-testing of pipeline by operators with less than 50C miles of pipeline is unknown. Informal discussions with pipeline operators indicate that muc’i pipeline mileage would have been re-tested frequently (e.g., every five years), while some mileage would not have been re-tested at all. Since most operators with less than 500 miles of pipeline appear to test their pipelines every 1 ive years or more often, it should only require minor changes in scheduling specific pipe segmenl s for assessment to assure that all pipe is inspected at least every five years. OPS therefore concludes that there could be limited additional assessment needed by operators with less tha 1 500 miles of pipeline in order to meet requirements for re-assessment at a five-year fi-equencj . For the reasons described above, OPS has again estimated for this analysis that 10 percent of impacted mileage will require unplanned assessment. Operators with less than 500 miles of pipeline will therefore need to assess an additional two percent of their impacted mileage annually (1 10 miles) to meet the requirements for subsequt nt assessment. OPS expects that operators will identify some pipeline in high consequence area s for which a longer inspection interval can be justified, and that they will seek OPS review to permit these segments to be tested at a longer interval. OPS has not adjusted this analysis to account for these longer-interval re-assessments, since the information obtained by informal discussions with operators indicates limited unplanned assessment should be required and ou r assumption that 10 percent of impacted mileage will require unplanned assessment should btlund any additional costs. Pipeline operators will need to do some subsequent testing at the same time they are doing baseline testing. This subsequent testing will begin in the sixth year of baseline testing, which is when mileage “baseline tested” in the first year after the final rule will need to be re-tested. During the sixth and seventh years of baseline testing, subsequent and baseline testing will overlap. Assuming that most re-testing would have been deferred until all initial testing was completed in the absence of a regulatory requirement, all subsequent testing in those two years will be over and above what would have been done in the absence of the rule. The full 1,09(1 miles undergoing subsequent testing during each of these two years is therefore assumed to be in excess of what would have been done. This analysis also assumes that 78 miles of additional pipeline must be inspected in each of these two years to complete baseline inspection (see ab we) so that the total of additional mileage that will require inspection during these years is 1,168 miles. 10#

Page 12Enhanced Leak Detection The rule includes criteria for operators to evaluate their leak detection capabilities and upgrad ; them where necessary. OPS does not know how many operators with less than 500 miles of pipeline currently have leak detection capabilities nor how many of those existing systems wi 1 require upgrading. Evaluation and upgrading, if necessary, of leak detection capability is integrally related to the required addition of mitigative features since leak detection would provide the information necessary to activate those mitigative features or procedures. Installation of EFRDs The OPS does not know how many of the manually operated block valves currently installed iin the 5,440 miles of impacted pipeline will be converted to EFRDs as a consequence of the regulatory change. (OPS also has no knowledge of other mitigation or prevention actions thal. might be taken.) It is estimated that 84.1 percent of all valves currently installed on hazardou;; liquid pipelines are manually operated block valve^.^ The rule specifies factors that operators must consider in deciding whether to convert these valves to remote operation or to install otl ier preventive or mitigative features. These factors are: swiftness of leak detection and pipeline shutdown capabilities type of commodity camed rate of potential leakage volume that can be released topography or pipeline profile potential for ignition proximity to power sources location of nearest response personnel specific terrain between the pipeline and the high consequence area benefits expected by reducing spill size Operators will only install EFRD’s in pipelines where installation of an EFRD would prove 1 o be beneficial. That is the cost of the installation and maintenance of the EFRD would be less than the potential benefit. BENEFITS To help reduce hazardous liquid pipeline incidents and their consequences, OPS is requiring that pipeline integrity management plans be developed and implemented by operators with less tl ian 5 Office of Pipeline Safety, Emergency Flow Restricting Devices Study (A Study Mandated by P.L. 100-561), 1. .S. DOT, April 1990. The original source of the information was reported to be the American Petroleum Institute. 11#

Page 13500 aggregate miles of pipeline. These plans are to provide for inspection and testing of pipeline that could affect high consequence areas, which are high-density population areas, navigable waterways, and unusually sensitive areas. In addition, the rule requires that the plans identify any sites where Emergency Flow Restricting Devices (EFRDs) would significantly reduce the risk to a high consequence area from a pipeline spill and that the operators install EFRDs at those sit :s and that affected operators evaluate leak detection capability and upgrade it if necessary. The benefits resulting from the regulatory change are discussed in this section. Those benefitis are expected to result from improvements in pipeline safety performance attributable primaril y to: ( 1 ) the development of a framework for integrity management that assists operators in determining and identifying risks to their pipelines in high consequence areas that could bene fit from periodic testing or other examination, (2) reassurance to the public that pipelines in higl-1 consequence areas receive the necessary levels of attention that ensure their integrity (3) increases in inspection and testing on pipelines in or near high consequence areas and (4) the installation of improved leak detection or additional EFRDs on pipelines in or near high consequence areas. Pipeline operators also have strong incentives to ensure the integrity of their pipelines. In addition to the positive safety and environmental benefits, the lost product and unscheduled downtime for repairs following a major incident can significantly impact the company’s final icial performance and its ability to satisfy customer commitments. Operators cannot afford to haw e these critical transportation assets out of service for lengthy periods of time in today’s competitive business environment. In addition, the damage to the company’s public image aiid reputation, as well as the legal implications of serious incidents, can pose an even broader a d longer term negative impact on the company’s business operations. For these and other reasc ns, many pipeline operators have implemented and are continuing to improve more systematic s ifety and environmental management processes. Development of Integrity - Plans And Framework The single most important part of this rule is the requirement for the integrity plan and framework. The creation, development and implementation of these documents will provide for the necessary integration of information regarding pipeline condition. Integration is importa nt to assure OPS, and the public, that pipeline operators are considering fully the unique risks tha hazardous liquid pipelines pose to high consequence areas. Plan development will assure ncit only that they are considering these risks but that they have developed a plan that requires e, tra scrutiny and precautions in these areas to safeguard the public and the environment. These safeguards include the use of periodic testing and the installation of EFRD’s where they are appropriate. The public is apprehensive that “aging” hazardous liquid pipelines pose a dangi :Tous threat to the safety and environmental health of their community. The development and implementation of an integrity management plan that requires a periodic testing schedule shimld provide the public as well as the OPS some level of assurance that pipeline operators have 12#

Page 14provided significantly to the protection of public safety and the environment in these sensitivt 8 areas. Since integrity management systems are not universal across the industry, OPS believes that i requirement that such plans be developed is necessary. The rule requires that plans be develo ped and specifies considerations that must be taken into account in that development. Developmt nt of the plans will involve consideration of risk factors unique to particular pipelines and high consequence areas. Operators will be required to establish a periodic assessment program in which all segments in high consequence areas are pressure tested or internally inspected no le ss frequently than once every five years, unless an exception is justified, and the entire pipeline s evaluated, and to determine how experience in other areas should be a factor in HCA’s. Evaluation is an ongoing process. Operators will be expected to consider the risk factors and their relative priorities in establishing assessment schedules. This allows operators to develo I an internal inspection and testing program that is customized to the particular operating characteristics and risks associated with different portions of their system(s). Inspection And Testing The inspection and testing required by the regulatory change will be some combination of in- line inspection (i.e., high resolution, low resolution, and ultrasonic instrumented pigging), pressui e testing (i.e., hydrostatic testing), and equivalent alternative testing (Le., testing using other techniques or tools that provide a level of safety and environmental protection comparable to pigging and hydrostatic testing). The change will spur operators with less than 500 miles of pipeline to identify and correct potential problems in pipelines in high consequence areas that might otherwise be missed. The main types of potential problems that can be helped by inspection and testing are those relatii lg to (1) intemal corrosion, (2) external corrosion, and (3) ruptures of previously damaged pipelinl:. Other types of potential pipeline problems may also be helped, but to a significantly lesser dt g e e than these. The expected benefit of increased internal inspection and pressure testing will be a reduction in incidents and incident consequences. Consequently, the benefits that are expected to result f 1-om the regulatory change are reduced (1) deaths, (2) major and minor injuries, (3) property damlige, (4) spilled product, (5) recovered product, (6) environmental damage, and (7) other consequences. Benefits of Increased Inspection and Testing The expected benefit of increased inspection and testing will be a reduction in incidents cau:,ed by internal corrosion, external corrosion, and ruptures of previously damaged pipeline and irl their consequences. This benefit will be a function of (1) the additional pipeline mileage tesled per year, (2) the expected reduction in incidents and consequences that will be attributable tci 13#

Page 15inspection and testing, and (3) the expected annual incident and consequence rates on the relevant mileage. The Additional Mileage Tested Per Year Additional mileage inspected and tested during the first five years following the effective datc of the rule will be 78 miles. During each of the next two years, 1,168 additional miles of pipelir e will be inspected and tested each year, and 1 10 additional miles of pipeline will be inspected md tested annually from then on (described above). With respect to deaths and serious injuries, the following assumptions are made: A life is valued at $2.7 million A serious injury is valued at $490 thousand These valuations are standard assumptions currently used in Office of Pipeline Safety and DC bT benefit/cost analyses. Enhanced Leak Detection and EFRDs In addition to inspection and testing, the regulatory change requires that leak detection be upgraded where necessary and that other preventive and mitigative actions be considered whl :re the benefit exceeds the costs. One example of such measures that is used here for purposes c f illustration is that Emergency Flow Restricting Devices (EFRDs) be installed at locations in I )r near high consequence areas where they would significantly reduce risk. (Operators could choose other methods of mitigation and prevention but they are not examined in this analysis .) Factors that must be considered in deciding whether to install EFRDs are specified in the rull : and were described above. The expected impact of the installation of additional EFRDs will be a reduction in the consequences of incidents attributable to (1) internal corrosion, (2) external corrosion, (3) ru iture of previously damaged pipe, (4) third party damage, (5) defective pipe, and (6) defective pip4 : seams.6 The consequences of other types of incidents may also be mitigated by EFRDs, but probably to a lesser degree than these. It should be noted that incidents will not be reduced tiy EFRDs, since EFRDs do not help prevent the occurrence of incidents. Benefit of Enhanced Leak Detection The benefit of improvements to leak detection will be quicker detection of any leaks or spillrr that could impact high consequence areas. Quicker detection will allow more rapid use of EFRTls or 60PS, Emergency Restricting Devices Study, April 1990. 14#

Page 16other mitigative devices. It will also allow swifter actions in response to leaks or spills that u ill help to minimize consequences. Benefit of EFRDs The benefit of EFRD installation will be a reduction in incident consequences for certain typt s of incidents. This impact will be a function of (1) the hazardous liquid pipeline mileage protect1 :d by the EFRDs, (2) the expected reduction in incident consequences that will be attributable tcl EFRDs, and (3) the expected annual incident and consequence rates on the impacted mileage COSTS The rule requires that, within one year of the effective date of the final rule, pipeline operator i: (1) identify areas that could be affected (2) prepare a written plan for initial (or baseline) assessment of all pipeline that could affect a high consequence area and (3) prepare a fi-amew ork addressing each element of an integrity management plan for their pipelines. These documer ts will detail testing methods to be used, risk factors considered in the selection of the appropri:ite testing methods for each particular high consequence area, and the schedule of testing and inspection. Appropriate testing methods include (1) pressure testing, (2) internal inspection, md (3) equivalent (in terms of level of safety provided) alternatives to pressure testing and intern 11 inspection. The plans will also include a site-specific risk assessment to determine whether I i x k detection capability needs to be upgraded and to identify sites where mitigation measures SUC h as Emergency Flow Restricting Devices (EFRDs) would significantly reduce risk. They will al: o include a schedule for EFRD installation or other mitigation measures, such as enhanced response procedures or management controls where required. Once the plans have been p r e p e d they will be used for baseline integrity testing. That testing must be completed within seven ;'ears of the effective date of the final rule (half of the testing must be completed within three and ( ne- half years of the effective date). OPS inspections will verify the plans and assure they are implemented thoroughly. Pipeline operators will be installing EFRDs at sites or taking other mitigation measures near high consequence areas where risk assessments indicate that they would significantly reduce risk. After the baseline testing has been completed, pipeline operators will be expected to periodic ally reassess the need for additional preventive or mitigative measures. Furthermore, they will bc : expected to retest their pipeline mileage in or near high consequence areas at least once ever#[ five years depending on risk factors. Based on the foregoing requirements, the costs that can be expected to result from the regula tory change will be those associated with the major provisions of this rule, which are: 1. Framework - setting up integrity management program; 2. Baseline assessment - internal inspection or pressure testing; 3. Periodic assessment (inspection) & evaluation; 15#

Page 174. Data integration; 5. Remedial action; 6. Enhanced leak detection; and 6. Mitigative measures (e.g., EFRDs). The Costs of Plans and Reports The plans and reports required by the regulatory change are: (1) a written plan for baseline assessment of all pipelines that could affect high consequence areas, (2) a framework addressing each element of an integrity management program, and (3) other documents supporting the decisions made, analyses made, and actions taken in the implementation of the integrity management program. Cost of the Written Plan and Framework Pipeline integrity management plans are relatively new. Experience in developing these plans has generally been with larger operators. Informal discussions with pipeline industry consultants indicate that these plans can cost anywhere from $75 thousand to $300 thousand. Well over ialf their cost would be expected to go toward the preparation of the plan (i.e., analysis and writirlg). The remainder would go primarily toward data gathering and computer programs needed to analyze that data. Integrity management plans that have been prepared voluntarily by some operators are more extensive than plans that would meet the minimum requirements specified in the rule. OPS I iotes that the plans required by many operators with less than 500 miles of pipeline will be simplei than an “average” integrity management plan for a large operator. For the purposes of this analysis, it is assumed that a written plan and framework prepared by a pipeline operator sol€ ly to comply with this rule will cost $75,000, the low-point of the estimated range. This estimate IS considered reasonable for operators with a few hundred miles of pipeline. OPS notes that co Sts could be considerably lower for operators with only a few miles of pipeline or a limited num )er of pipehe segments (separate locations that must be considered). OPS has not attempted to determine how many of the operators with less than 500 miles of pipeline fall into this categc ~ r y and has, instead, conservatively used the same cost estimate for all operators potentially subj i:ct to the rule. Other Supporting Documents Operators will have to evaluate new information that may affect their integrity programs and revise those programs as needed. New information could include, for example, new inspecti on technology, changes to the pipeline system or its operation, and changes to the boundaries oj high consequence areas. The annual effort required to modify the programs on a continuing basis is expected to be considerably less than the effort needed to prepare the programs in the first pl ace. OPS has estimated this annual effort at $8,000 per year. 16#

Page 18It is expected that the supporting documents that will be created will be primarily record keep ing associated with periodic assessment. This record keeping, although important, is expected to require minimal time and resources. The documents are expected to be prepared by junior stz ff at the pipeline, under the oversight and management of senior staff. They are expected to tak ; no longer than two labor weeks to produce. It is estimated that they will have a total cost of $2,C 00. For the purposes of this analysis, it is assumed that these reports will be produced annually. Here again, OPS considers these estimates reasonable for operators with a few hundred miles of pipeline. Costs for operators with only a few miles of pipeline in a limited number of locatio IS will be lower. Total Cost of Plans and Reports There are 132 hazardous liquid pipeline operators who could potentially be subject to the regulatory change. Some of these companies operate only a few miles of pipeline and may h; we no pipeline that would affect a high consequence area. Such companies would not be subjecl to the rule. Some companies included among these 132 are affiliated with other, larger, hazardc pus liquid pipeline operators and their piping may be addressed in plans developed by those oper; itors in response to a previously-issued rule. OPS does not yet know whether any operators have I LO pipe that could affect a high consequence area nor does OPS know how many will be encompassed in the plans of operators with greater than 500 miles of pipeline, and has conservatively assumed that all 132 operators with less than 500 miles of pipeline will be affected. Each of those operators will need to perform annual documentation and updates. 1 he cost of these activities is conservatively estimated to be $1.32 million per year. The Office of Pipeline Safety expects that virtually all of the operators with less than 500 mi es of pipeline will not have existing plans and will need to develop plans in accordance with tht rule (costing $75 thousand each). The total cost of those plans will be $9.9 million. This cost will only be incurred once. Based on the foregoing, the total cost for plans and reports will consist of a one-time cost of ~$9.6 million plus an annual cost of $1.32 million.' The Costs of Testing Baseline and periodic testing will be required by the regulatory change. That testing will be accomplished by an appropriate combination of: (1) pressure testing, (2) internal inspection, and (3) alternative testing and inspection methods. For the purposes of this analysis, it is assumz d that all required testing will be accomplished by either (1) hydrostatic testing (pressure testirig) or 'This does not include cost incurred by the Federal government in setting up the review process (including development of review protocols and training) and in the actual review of the plans and programs. 17#

Page 190 (2) smart pigging (internal inspection). Alternative methods are not yet to the point where the ir costs for pipeline testing can be reliably estimated. It is assumed that it will be sufficient to perform either hydrostatic testing or smart pigging, and not both, in order ensure the integrity ‘of any particular segment of pipeline. Hydrostatic Testing The total cost of hydrostatic testing has been previously estimated by the OPS to be $4,656 pc::r mile in 1990 dollars,’ which equates to $5,777 per mile in 1998 dollars. This estimate includ.:s the following costs: 0 Cost of performing the actual hydrostatic test Cost of acquisition, transfer and disposal of test water Loss of revenue due to the use of storage tanks for holding test water Loss of pipeline tariff revenue due to pipe being out of service for testing The estimate does not include the cost of making any repairs to the pipe. The 1990 estimate s based primarily on information obtained by the OPS from various industry sources. Smart Piaaing The total cost of smart pigging has been previously estimated by the OPS to be $2,839 per mile in 1992 dollars: which equates to $3,043 per mile in 1998 dollars. This estimate does not include the cost of making a pipeline piggable (i.e., adding pig launchers and receivers or modifying pipeline that cannot pass instrumented pigs). Some hazardous liquid pipeline mileage is not currently piggable. Informal discussions with pipeline operators indicate that 60 to 75 percent of hazardous liquid pipeline mileage of ope1,ators with less than 500 miles of pipeline is piggable. (Most operators whose lines are not piggab’e indicated that they rely on routine pressure testing to verify pipe integrity. This accounts for the conclusion already stated that most pipe of operators with less than 500 miles of pipeline is currently being tested). For the purposes of this analysis, it is assumed that 70 percent of all impacted mileage is currently piggable. ’Office of Pipeline Safety, “49 CFR Part 195 Economic Evaluation, NPRM - Hydrostatic Testing of Certain Hazardous Liquid and Carbon Dioxide Pipelines,” Docket No. PS-121, Notice 1, May 13, 1991. ’Office of Pipeline Safety, Instrumented internal inspection Devices (A Study Mandated by P.L. 100-.561), Re {earth and Special Programs Administration, November 1992, p. C-2. 18#

Page 20The costs of making hazardous liquid pipeline piggable are presented in Exhibit 1. The origir a1 sources of the costs in Exhibit 1 were submissions by liquid pipeline operators to the U.S. DC T’s Docket No. PS-105; Notice 1 .lo Exhibit 1. Costs of Making Hazardous Liquid Pipeline Piggable (1 992 dollars per mile) Source: OPS, Instrumented Internal Inspection Devices, November 1992, p. 24. Exhibit 2 presents estimated costs for making hazardous liquid pipeline piggable. These estimates are the mid-points of the costs presented in Exhibit 1, converted from 1992 to 1998 dollars per mile. Exhibit 2. Estimated Costs of Making Hazardous Liquid Pipeline Piggable (1 998 dollars per mile) Source: The mid-points of the ranges presented in Exhibit 1 in 1998 dollars. Hydrostatic Testinn vs. Pinging Informal discussions with pipeline operators suggest that, all other things being equal, piggirig is much preferred to hydrostatic testing, at least in part because pigging can provide more valu;i.ble information to operators than hydrostatic testing and because pigging is not destructive, while hydrostatic testing can be. Consequently, it is assumed that pigging will be the testing methc id used on all piggable pipeline mileage. Also, it is assumed that pipeline mileage that is not currently piggable will not be made piggable because of the relatively high costs of doing so (see Exhibit 2). ‘OOPS, Instrumented Intemal Inspection Devices, November 1992, p. B-2. 19#

Page 21Additional Mileage Must Be Tested It is usually not possible to hydrostatically test or pig pipe in high consequence areas without , tlso testing some adjacent piping. Hydrostatic testing requires valves that can isolate the pipe segment being tested. Pigging must be run between available pig launchers and receivers, which are seldom located immediately adjacent to the boundaries of high consequence areas. For purposes of this analysis, OPS has estimated that the amount of additional piping that will necsd to be tested in order to complete the required testing in high consequence areas is 25 percent uf the amount of piping in the areas. The estimates of required testing above reflect the amount of pipe that must be tested due to the requirements of the rule. The cost estimates which follow are based on totals that are 1.25 times that mileage. Cost of Baseline Testing To meet the requirements for baseline testing, operators with less than 500 miles of pipeline ,will need to test annually 78 miles of pipeline beyond that already planned over a seven year pericld (see earlier discussion). It is expected that 70 percent of this mileage will be pigged, while the other 30 percent will be hydrostatically tested, and that 25 percent additional piping will neec to be tested. Operators with less than 500 miles of pipeline will incur an additional cost of $377,000 annually (in 1998 dollars) to perform baseline testing. Cost of Subsequent Testing To meet the requirements for subsequent testing, operators with less than 500 miles of pipeli ie will need to test annually 1,090 additional miles of pipeline during each of the first two years of re-testing, and 110 additional miles of pipeline every year thereafter (see earlier discussion). It is expected that 70 percent of this mileage will be pigged, while the other 30 percent will k e hydrostatically tested, and that 25 percent additional piping will need to be tested. Operators with less than 500 miles of pipeline will be expected to incur an additional cost of $5.26 mil ion (in 1998 dollars) per year during each of the first two years of re-testing and $531,000 (in 19'98 dollars) per year during every year thereafter because of the requirement for subsequent testi ig. This additional cost will not start being incurred until the sixth year after the effective date of the final rule, the year in which the mileage baseline tested in the first year will need to be re-tested. Total Cost of Testing The total cost of testing will be the sum of the cost of baseline testing, $377 thousand per yeiu for the first seven years, and the cost of subsequent testing, $5.2 million per year for years six and seven and $53 1 thousand for years eight and on. The Costs of Data Integration 20#

Page 22As described above, integration of all information relevant to the integrity of the pipeline is a key element of the integrity management plans required for high consequence areas. Assuring thiis integration will require that operator’s internal data management systems be aligned and managed in such a way that relevant information is brought together. It will also require that ,the importance of this information be assessed by experienced pipeline safety professionals. Operators with less than 500 miles of pipeline are expected to develop integrity management plans in response to this rule and will need to implement new actions to assure data integratic n. These actions will need to include realignment of data management systems that will occur iri the first year (concurrent with development of the integrity management plan) and continuing coi,ts for assessment of the integrated data. OPS estimates that first year costs for the impacted operators will be $50 thousand, and that continuing costs will be $25 thousand annually thereafter. As with the estimates for developing integrity management plans, OPS considers these estim ites to be reasonable for operators with a few hundred miles of pipeline. Again, costs will be less for operators with only a few miles of pipeline in a limited number of locations. OPS has conservatively used these estimates in this analysis for all operators potentially subject to the rule. Total costs for data integration for the 132 operators that are expected to develop plans will be $6.6 million in the first year and $3.3 million annually in following years. The Cost of Remedial Action Inspection and testing and integration of other relevant data will identify anomalies that mus be investigated and remediated. OPS has no information on which to base assumptions regardi ig the number of anomalies that will require action nor on the cost of that action. Costs associated with remediation are therefore not estimated as part of this analysis. The Costs of Enhanced Leak Detection OPS understands that leak detection adequate for the purposes of this rule can be provided through upgrades of Supervisory Control and Data Acquisition (SCADA) systems. Other methods of leak detection are also used. Based on informal discussions with an industry expert in leak detection, OPS estimates that ithe software required to enhance SCADA systems for leak detection costs approximately $100,000 Approximately six man-months of effort, at a cost of $100,000 would be required to configt re and test the system. An additional three man-months, or approximately $50,000 will be req iired to link the SCADA data. Additional flow metering, if required, would cost an additional $100,000 per location (required every 200 miles). Once installed, annual maintenance costs are approximately $20,000 to $40,000 per year. 21#

Page 23OPS does not know how many operators with less than 500 miles of pipeline currently have SCADA systems configured for leak detection or have other leak detection systems. OPS is therefore unable to estimate the total costs for upgrading leak detection systems. The Cost of EFRDs EFRDs are pipeline valves specifically installed to help limit the loss of product when there h,as been a break in a pipeline. Two kinds of EFRDs are considered by the Office of Pipeline Saf .:ty to be effective: check valves and remotely controlled valves. A check valve is one that allou s fluid to flow fieely in only one direction. A remotely controlled valve is a block valve that cz n be opened and closed from a remote location. Generally, that location is the pipeline’s contrd center. Because remotely controlled valves provide pipeline operators with greater control than check valves, it is assumed that any EFRDs installed will be remotely controlled valves. Estimated Costs In 1994, the OPS issued an advanced notice of mlemaking (ANPRM) concerning EFRDs (se: 59 Federal Register, Jan. 19, 1994). That EFRD ANPRM requested information from the pipeliiie industry concerning, among other things, the costs of EFRDs, specifically, remotely controllc d valves. Eight usable responses were received by the docket from hazardous liquid pipeline operators. Some of these responses provided separate information for multiple segments of respondents’ pipeline systems. The responses to the EFRD ANPRM relating to cost are summarized in Exhibits 3,4, and 5. The cost estimates in the exhibits are presumed to be gi1:en in 1993 nominal dollars. 22#

Page 24EXHIBIT 3. COSTS FOR INSTALLING NEW RCVS AS REPORTED BY RESPONDENTS TO THE EFRD ANPRM Average Minimum Maximum Valve Diameter (inches) 15 4 45 Cost of RCV $96,500 $9,500 $231,000 Communication Cost $7,400 $1,000 $20,000 Other Installation Costs $9,300 $0 $50,000 Total Installation Cost' $117,200| $33,500| $301,000 Source: Responses by pipeline operators to Question 11 in the EFRD ANPRM. Notes: 1. The totals represent the values provided by the respondents to the EFRD ANPRM, not the sums of the relevant cost categories in the table. Some respondents to the ANPRM did not provide usable information for all cost categories. • 23#

Page 25EXHIBIT 4 COSTS TO CONVERT MANUALLY OPERATED BLOCK VALVES TO REMOTELY CONTROLLED VALVES AS REPORTED BY RESPONDENTS TO THE EFRD ANPRM Average Minimum Maximum Valve Diameter (inches) NA' = - 45 Installation Cost $51,100 $2,000 $89,6010 Communication Svstem Cost $7.400 $278 $20.000 Other Installation Cost $2,300 $0 $16,0C0 Total Installation Cost? $60,600 $5,056 $103,6CQ Source: Responses by pipeline operators to Question 10 in the EFRD ANPRM. Notes: 1. An average value for the valve diameter could not be calculated because some respondents did not identify a not the sums of the relevant cost categories in the table. Some respondents to the ANPRM did not provide usat le information for all cost categories. EXHIBIT 5. ANNUAL COSTS ASSOCIATED WITH REMOTELY CONTROLLED VALVES THAT WERE REPORTED BY RESPONDENTS TO THE EFRD ANPRIV Average Minimum Maximum Valve Diameter (inches) NA' 45 Annual Operating Cost $1,500 $200 $4,000 Annual Maintenance Cost $1,400 $500 $3,000 Other Annual Costs $300 $0 $5,000 Total Annual Cost' $3,400 $2,000 $49,500 Source: Responses by pipeline operators to Question 10 in the EFRD ANPRM. These reprrsent the estimated annual costs associated with RCVs that were converted manually operated blo:k valves. Notes: See Exhibit 4. 24#

Page 26Exhibit 6 presents estimates for: (1) the costs of installing a new remotely controlled valve, (2) the costs of converting a manual block valve into a remotely controlled valve, and (3) the ann la1 operating, maintenance, and other costs associated with a remotely controlled valve. Those estimates are the totals from bottom of the “Average” columns in Exhibits 3,4, and 5, converted to 1998 dollars and rounded to the nearest $100. EXHIBIT 6. ESTIMATED EFRD COSTS (1998 Constant Dollars) Cost of Installing a New RCV $1 24,000 Annual Cost of an RCV $3,500 Number of EFRDs Installed or Converted from Manually berated Block Valves Valves (including EFRDs) on line pipe used in the transport of hazardous liquids have been reported to be spaced an average of 13.6 miles apart.” This means that the 5,440 miles of pipeline impacted by the regulatory change will have approximately 400 valves. About 84.1 percent of those valves are believed to be manually operated block valves.I2 This means that approximately 336 are manually operated valves. OPS does not know how many EFRD’s w 11 be installed and seeks comments from the public. TOTAL COSTS Costs have been estimated for: (1) plans and reports, (2) testing, (3) data integration, and (4) leak detection and EFRDs. In Exhibit 7, those costs are totaled and presented by the year that the:y are incurred after the effective date of the final rule. “OPS, Emergency Flow Restricting Devices Study, April 1990. ‘‘OPS, Emergency Flow Restricting Devices Study, April 1990. 25#

Page 27EXHIBIT 7. THE ESTIMATED COST OF THE REGULATORYCHANGE (Costs in thousands of 1998 dollars) Year Integrity Annual after Plans' Reports' Baseline Subsequent Data EFRD* Total Testing Testing Integration+ Installation; Cost effective Leak date of Detection final rule Upgrade 1 1 $9.940 $1.320 $377 $0 $6.600 $13.237 2 $0 $1.320 $377 $0 $3.300 $4.997 3 $0 $1.320 $377 $0 $3,300 $4,997 4 $0 $1,320 $377 $0 $3,300 $4,997 5 $0 $1,320 $377 $0 $3,300 $1,997 6 $0 $1,320 $377 $5,260 $3,300 $110257 7 $0 $1,320 $377 $5,260 $3,300 $10,257 8 - 20 $0 $1,320 $0 $531 $3.300 $5.151 *OPS did not estimate the number of EFRDs that would be installed. However OPS believes operators will only install EF RDs where cost exceeds benefits. OPS also did not estimate the total cost for upgrading leak detection systems. the earlier rule. affiliated with larger operators and are encompassed within activities those companies have already implemented in respon e to CONCLUSIONS Issuance of this rule as a national standard will ensure that all operators will perform at least to a baseline safety level and will contribute to an overall higher level of safety and environment;l performance nationwide. It will lead to greater uniformity in how risk is evaluated and addrissed and will provide more clarity in discussion by government, industry and the public about safety and environmental concerns and how they can be resolved. The flexibility of a performance-based approach provides several advantages. It encourages development and use of new technologies. It is an important feature in supporting operators' 26#

Page 28development of more formal, structured risk evaluation programs and RSPA’s evaluation of them. It also provides greater ability for operators to customize their long term maintenance programs. It has also stimulated the development of a supplemental industry standard which v 4 l be of assistance in implementation of this rule. A performance-based approach will also encourage the development and maturing of risk-based approaches to integrity management. Our emphasis on the integrity management system encourages a balanced program, addressin :; the range of prevention and mitigation needs and avoiding reliance on any single tool or overemphasis on any single cause of failure. This orientation will lead to addressing the mosl significant risks, and is the best opportunity to improve industry performance and assure that he high consequence areas get the protection they need. It also addresses the interrelationships among failure causes and benefits. It promotes the coordination of risk control actions, beyorld what a compliance-based approach would achieve. The rule provides for a verification process, which gives the regulator a better opportunity to influence the methods of assessment and the interpretation of results. This is not to say the regulator would overstep the bounds of oversight, but would provide a beneficial challenge tcl the adequacy of the operators’ decision process. This leads to greater accountability to the public. This accountability is enhanced through our choice of a map-based approach to defining the i reas most in need of additional protection - the visual depiction of the areas in need of protection brings a focus on the safety and environmental issues in a manner that will be easily understandable to everyone. A particularly significant benefit is the quality of information that will be gathered as a result of this rule to aid operators’ decisions about providing additional protections. Two essential elements of the integrity management program are that an operator continually assess and evaluate the pipeline’s integrity, and perform an analysis that integrates all available informal ion about the pipeline’s integrity. The process of planning, assessment and evaluation will provi le operators with better data on which to judge a pipeline’s condition and the location of potent a1 problems that must be addressed. Integrating this data with the environmental and safety concerns associated with high consequence areas will help prompt operators and the Federal and state governments to focui,, time and resources on potential risks and consequences that require greater scrutiny and the rleed for more intensive preventive and mitigation measures. If baseline and periodic assessment 1 lata is not evaluated in the proper context, it is of little or no value. It is imperative that the information an operator gathers is assessed in a systematic way as part of the operator’s ongcling examination of all threats to the pipeline integrity. The rule is intended to accomplish that. The cost estimates for testing in this evaluation reflect the fact that operators have begun tesi ing programs and would be expected to continue those programs without this rule. The rule reqr [ires specifically that piping that can affect high consequence areas be included in these testing programs and that the rate of testing of such piping be accelerated. Costs for the required acceleration have been estimated at $377,000 annually during the first five years, and are 27#

Page 29considered reasonable. Costs of leak detection upgrades and other preventive or mitigation measures including EFRD installation and maintenance were not included because OPS did ni It know how many operators would need to install these devices. However, the rule requires the se devices only where they would be effective. OPS believes operators would only be required tl) install EFRDS’s where their benefit is at least equal to the cost. The costs of this rule increase in the sixth year because of the need to retest the lines. OPS mi’iy in fact be overestimating the cost of the retest requirement as operators might have voluntarilj, retested their lines in high consequence areas within the 6 year time-frame. The state of California already requires hydrostatic testing every 5 years. While OPS has not performed a quantitative benefit analysis of this rule OPS strongly believes that this rule is indeed cost-beneficial. The cost for all hazardous liquid pipeline operators wi1.h less than 500 miles of pipeline to develop plans is a modest $9.9 million with an additional $ .32 for annual updates. Total costs for data integration are estimated at $6.6 million for the first )‘ear, during which company data systems must be adjusted, and $3.3 million annually thereafter. 1:ach of these costs is conservatively bounded since OPS has assumed that all 132 pipeline operatoi s potentially impacted by this rule will actually be affected at an “average” level. In fact, some of these operators may have no pipeline that could affect high consequence areas and will thus n,ot be impacted by the rule. Some of these operators may have only a few miles of pipeline and .,vi11 incur significantly less cost. Some of these operators may be encompassed within plans of la.ger corporate affiliates and will therefore incur no additional costs. OPS believes that the process of developing an integrity framework and schedule and integra ing data related to pipeline integrity is an important process for the operator, the government and the general public. The creation, and development of the plan will alert operators of the potential risks and consequences unique to high consequence areas. The planning process, including t le testing schedule, also provides a level of confidence to Federal and state pipeline inspectors that pipeline operators are considering, examining, testing, and repairing if necessary, hazardous liquid pipelines that potentially pose severe consequences to public safety and environmental health. Finally, the public, which has indicated concems that “aging” hazardous liquid pipeli nes pose to their neighborhoods, will be afforded an additional level of confidence. Additionally, standardizing the requirements nationally for hazardous liquid pipeline will save operators having to face potentially different testing and inspection requirements from the various state pipeline agencies. Finally, although OPS has not provided quantitative benefits for the retesting provision of th s rule OPS does not believe that requiring retest of pipelines in high consequence areas on a minimum schedule of once every five years will be an undue burden on hazardous liquid pipIAine operators. Industry-wide costs for retesting are estimated to be $53 1 thousand per year ($5.2 6 million in years six and seven due to overlap of baseline testing and initial retesting). Total damages from the recent PEPCO spill are estimated to range from $50 million to $75 million. Preventing one such accident every few years would offset the cost of testing. Beyond the 28#

Page 30quantitative benefit, though, OPS believes the sense of security that this test gives the general public is benefit enough to require this test every five years. RESPONSE TO COMMENTS Two of the comment letters submitted in response to the Notice of Proposed Rulemaking addressed the draft Regulatory Evaluation: the Small Business Administration (SBA), and Laclede Pipeline Company. The response to those comments is provided below. The SBA objected to the lack of inclusion of equipment and maintenance costs, particularly f i3r EFSDs and leak detection systems. As described above, and similarly described in the draft Regulatory Evaluation, OPS did not estimate these costs because we do not know how many operators will install such equipment. SBA suggested that costs could be estimated by parametric analyses, varying the number of operators that will install the devices. (SBA mad: additional comments related to the discussion of Regulatory Flexibility Act compliance. These comments have been addressed in the Regulatory Flexibility Act discussion in the preamble (:If the final rule.) OPS does not believe it is practical to perform the parametric analyses suggested by SBA. A's noted, we do not know how many operators will install leak detection systems or EFRDs. We could make certain assumptions regarding the percentage of operators who will need to makc changes, but that is only one variable. The number of devices that any individual operator might need is also unknown. The cost to install EFRDs can vary significantly. It depends on the circumstances of the individual pipeline, including its size, and on the locations in which the installations must be made. Costs to install valves in areas unusually sensitive to environmei ita1 damage can be very large, and the environmental impact of such installations can, itself, sometimes be prohibitive. Assumptions would need to be made regarding these variables as well. In the end, we could produce an analysis that would include quantitative values, but W I : could not have any confidence that those numbers would be representative of the actual situation within the pipeline industry. As such, we believe they would obfuscate, rather than inform, public decisionmaking. Laclede Pipeline Company commented that the proposed rule was unreasonable, arbitrary, ai id capricious. Their basis for this comment was threefold: 1) that 70 percent of their 28-mile limpid propane pipeline cannot be assessed with internal inspection devices, that system design WOI ild make de-watering after a hydrostatic test difficult, and that freezing of moisture remaining a ter such a test could cause service interruptions, 2) the company has already installed emergency shutdown valves at many of its pipeline valve locations that provide protection from rupture,;, and 3) that implementation costs have been grossly underestimated. Laclede suggested that /.he rule should exempt pipelines directly serving local distribution systems (natural gas) providtmd that such pipelines are cathodically protected and satisfy OPS and DOT Safety Inspection Standards. Laclede also suggested that operators who have installed extensive emergency flow restricting or emergency shutdown devices should be exempted. 29#

Page 31OPS does not agree that blanket exceptions to the rule are appropriate. The particular circumstances of individual pipelines differ. EFRD’s and ESDs, while valuable, do not prevent pipeline leaks or ruptures. The specific number and location of EFRDs or ESDs is particularly important in determining their effectiveness in mitigating potential pipe ruptures. The brief description provided in Laclede’s comment does not allow OPS to conclude that periodic assessment of the company’s pipeline to assure integrity is not needed. Laclede, and other pipeline companies, can apply for a waiver based on particular pipeline design and circumstances. With respect to hydrotesting, OPS recognizes that such testing must be done with caution, ani I that dewatering lines after a test is important. Hydrotesting is not new. The provisions alreacly included in 49 CFR 5 195.302 require hydrotesting, including when pipe is replaced, relocate:$ or otherwise changed. Laclede’s comments indicate that portions of its pipeline have been replaced. Hydrotesting would then have been required, and the same dewatering concerns wwld have had to be addressed. OPS does not agree that requiring periodic assessment that may require hydrotesting is unreasonable, arbitrary and capricious. Laclede contends that the NPRM was wrong in that it estimated 50 percent of affected pipelii tes can be pigged while 70 percent of Laclede’s cannot. This argument is simply not persuasive. Thirty percent, a non-insignificant portion, of Laclede’s pipeline can be pigged. As Laclede points out, its pipeline represents only a small portion of the pipeline affected by this rule nationally. The principal element of Laclede’s contention that the rule is unreasonable, arbitrary, and capricious, however, rests with its contention that the costs of implementation have been gro ,;sly underestimated. In this regard, the company has seriously misrepresented the situation. Lac1 ede notes that OPS’s estimate of the cost for all affected operators is $9.64 million (revised to $9.94 million in this final regulatory evaluation due to an increase in the number of companies potentially affected by the rule) whereas Laclede itself expects to incur costs in excess of $1 million to modify its pipeline. Laclede is comparing apples and oranges. Laclede’s estimated costs are to replace piping that can not now be pigged. The rule does not require such pipe replacement, and costs for such replacement therefore were not included in the implementation cost estimate. The rule allows use of hydrotesting which, as noted earlier, is an existing testing method embodied in the regulations. Laclede’s replacement of piping to allow pigging, if undertaken, would be an operational choice based on the company’s conclusion that pigging would be a better method of assessment for their situation than hydrotesting. Companies arc: certainly free to make such operational choices, but they are not required by the rule and c0sI.s associated with pipe replacement are not, therefore, a cost for implementing the rule. The Department of Energy (DOE) also submitted comments pertaining to the draft Regulatory Evaluation. DOE expressed concern that costs associated with down time during inspections or with permitting costs for conducting repairs may not have been included, and that per-mile estimates may not be appropriate for operators with only a few miles of pipe. DOE also suggested that future developments may make it difficult for operators to comply with the time 30#

Page 32requirements for conducting baseline assessments and periodic re-assessments, and having thc :m reviewed. (DOE acknowledged that the proposed time frames for these activities appear reasonable today). DOE also expressed concern that the requirements may have an unreason2 ble impact on some small operators. The values used to estimate costs for pigging and hydrostatic testing were based on detailed studies of both methods, which considered all relevant costs. The outcome of those studies which is used in the Regulatory Evaluation is, indeed, per-mile estimates for conducting thest’ assessments. OPS recognizes that costs may be higher for operators that only have a limited amount of pipe, and for whom “fixed” costs associated with conducting the assessments musl be amortized over the small length of pipe. OPS is unable to estimate how many operators may be so affected. Many of the operators affected by this rule, however, are parts of larger companiizs, as described further in response to Small Business Administration comments, and should not be so affected. OPS will work with operators who may be unusually impacted, each of whom n- ay request waivers as appropriate. While costs for permitting associated with conducting assessments were included, permitting costs associated with repairs were not estimated. No repair costs were included in the Regulatory Evaluation. This rule does impose time limits on the repair of certain types of defects. Generally, however, repair of conditions that could adversely affect safe operation of a pipeline is already required by 49 CFR 5 195.401. Repair is thus not a new requirement in this rule. As to potential future problems in meeting the time requirements in the rule, OPS considers I hem speculative. It is possible that new pipelines and increased demand for the expertise necessa y to conduct assessments could result in problems, as suggested by DOE. It is equally plausible, however, that this rule will foster increases in the resources available to operators for that purpose. OPS concludes that changes to the required time frames are not appropriate at this time. Problems that may arise in the fbture will be addressed at that time. The Small Business Administration (SBA) also commented on possible impacts on small businesses. As described in the discussion of Regulatory Flexibility Act considerations in thl? preamble to the rule, OPS has considered such impacts. Many of the companies potentially affected by this rule are affiliated with larger companies. Few meet the SBA criteria for sma I1 businesses (500 employees for hazardous liquid pipeline companies). OPS will work with a,iy small operators who may experience unusual impacts, any of whom can apply for waivers. 31#

Page 33SELECTED BIBLIOGRAPHY American Petroleum Institute, Analysis of DOT Reportable Incidents for Hazardous Liqulid Pipelines, 1986 Through 1996, API Publication 1158, Washington, DC, January 7 , 1999. Helton, Douglas and Penn, Tony, Putting Response and Natural Damage Costs in Perspective, 1999 International Oil Spill Conference, Paper #114 Office of Management and Budget (OMB), Circular No. A-94, Revised (Transmittal Memo No. 64, October 29,1992), Appendix C (revised January 1999). Office of Pipeline Safety, “49 CFR Part 195 Economic Evaluation, NPRM - Hydrostatic’ Testing of Certain Hazardous Liquid and Carbon Dioxide Pipelines,” Docket Nc. PS-121; Notice 1, May 13,1991. Office of Pipeline Safety, Emergency Flow Restricting Devices Study (A Study Mandated by P.L. 100-561), OPS, Research and Special Programs Administration, Washingto 11, DC, April 1990. Office of Pipeline Safety, Instrumented Internal Inspection Devices (A Study Mandated b i v P.L. 100-561), OPS, Research and Special Programs Administration, Washington, DC, November 1992. Office of Pipeline Safety, Office of Pipeline Safety User Fee Assessments, OPS, Washington, DC. 32#